10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________________________

FORM 10-K

(Mark One)
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2021
☐	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 or Organization	IRS Employer Identification Number
1-12609	PG&E CORPORATION	California	94-3234914
1-2348	PACIFIC GAS AND ELECTRIC COMPANY	California	94-0742640

77 Beale Street				77 Beale Street
P.O. Box 770000				P.O. Box 770000
San Francisco,	California		94117	San Francisco,	California		94117
(Address of principal executive offices) (Zip Code)				(Address of principal executive offices) (Zip Code)
	415	973-1000			415	973-1000
(Registrant’s telephone number, including area code)				(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

Securities registered pursuant to Section 12(g) of the Act: none

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation:	☒	Yes	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
PG&E Corporation:	☐	Yes	☒	No
Pacific Gas and Electric Company:	☐	Yes	☒	No

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

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
PG&E Corporation:	☒	Yes	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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			Pacific Gas and Electric Company
	☒	Large accelerated filer		☐	Large accelerated filer
	☐	Non-accelerated filer		☒	Non-accelerated filer
	☐	Smaller reporting company		☐	Smaller reporting company
	☐	Accelerated filer		☐	Accelerated filer
	☐	Emerging growth 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
PG&E Corporation:	☒
Pacific Gas and Electric Company:	☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:	☐	Yes	☒	No
Pacific Gas and Electric Company:	☐	Yes	☒	No

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2021, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation common stock	$20,185 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

Common Stock outstanding as of February 4, 2022:
PG&E Corporation:	2,463,891,104*
Pacific Gas and Electric Company:	264,374,809
*Includes 437,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 40,000,000 shares of common stock held by Pacific Gas and Electric Company.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:

Designated portions of the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

Contents

Triple Bottom Line

CRITICAL ACCOUNTING ESTIMATES

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NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 5: DEBT

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

NOTE 7: PREFERRED STOCK

NOTE 8: EARNINGS PER SHARE

NOTE 9: INCOME TAXES

NOTE 10: DERIVATIVES

NOTE 11: FAIR VALUE MEASUREMENTS

NOTE 12: EMPLOYEE BENEFIT PLANS

NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS

NOTE 14: WILDFIRE-RELATED CONTINGENCIES

NOTE 15: OTHER CONTINGENCIES AND COMMITMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 34)

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UNITS OF MEASUREMENT

1 Kilowatt (kW)	=	One thousand watts
1 Kilowatt-Hour (kWh)	=	One kilowatt continuously for one hour
1 Megawatt (MW)	=	One thousand kilowatts
1 Megawatt-Hour (MWh)	=	One megawatt continuously for one hour
1 Gigawatt (GW)	=	One million kilowatts
1 Gigawatt-Hour (GWh)	=	One gigawatt continuously for one hour
1 Kilovolt (kV)	=	One thousand volts
1 MVA	=	One megavolt ampere
1 Mcf	=	One thousand cubic feet
1 MMcf	=	One million cubic feet
1 Bcf	=	One billion cubic feet
1 MDth	=	One thousand decatherms

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GLOSSARY

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

2021 Form 10-K	PG&E Corporation’s and Pacific Gas and Electric Company’s combined Annual Report on Form 10-K for the year ended December 31, 2021
AB	Assembly Bill
AFUDC	Allowance for Funds Used During Construction
Amended Articles	Amended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB
Bankruptcy Code	the United States Bankruptcy Code
Bankruptcy Court	the U.S. Bankruptcy Court for the Northern District of California
BPP	bundled procurement plan
CAISO	California Independent System Operator Corporation
Cal Fire	California Department of Forestry and Fire Protection
CAPP	California Arrearage Payment Program
CARB	California Air Resources Board
CARE	California Alternate Rates for Energy Program
CCA	Community Choice Aggregator
CCPA	California Consumer Privacy Act of 2018
CEC	California Energy Resources Conservation and Development Commission
CEMA	Catastrophic Event Memorandum Account
Chapter 11	Chapter 11 of Title 11 of the U.S. Code
Chapter 11 Cases	the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Order	the order confirming the Plan, dated as of June 20, 2020 with the Bankruptcy Court
CHT	Customer Harm Threshold
CPIM	Core Procurement Incentive Mechanism
CPPMA	COVID-19 Pandemic Protections Memorandum Account
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
CVA	Climate Vulnerability Assessment
DA	Direct Access
Diablo Canyon	Diablo Canyon nuclear power plant
DOE	U.S. Department of Energy
DTA	deferred tax asset
DTSC	Department of Toxic Substances Control
EMANI	European Mutual Association for Nuclear Insurance
Emergence Date	July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EO	Executive Order
EOEP	Enhanced Oversight and Enforcement Process
EPA	U.S. Environmental Protection Agency
EPS	earnings per common share
EPSS	Enhanced Powerline Safety Settings
EV	electric vehicle
EVM	enhanced vegetation management
Exchange Act	Securities Exchange Act of 1934
FASB	Financial Accounting Standards Board

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FERC	Federal Energy Regulatory Commission
FHPMA	Fire Hazard Prevention Memorandum Account
Fire Victim Trust	The 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
FRMMA	Fire Risk Mitigation Memorandum Account
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GO	general order
GRC	general rate case
GT&S	gas transmission and storage
HFTD	high fire-threat districts as set forth in the CPUC Fire-Threat Map
HSM	hazardous substance memorandum account
IRC	Internal Revenue Code
IRP	Integrated Resource Planning
IOUs	investor-owned utility(ies)
Kincade Amended Complaint	The amended criminal complaint filed by the Sonoma County District Attorney’s Office on January 28, 2022 in connection with the 2019 Kincade fire
Kincade Complaint	The criminal complaint filed by the Sonoma County District Attorney’s Office on April 6, 2021 in connection with the 2019 Kincade fire
Lakeside Building	300 Lakeside Drive, Oakland, California, 94612
LIBOR	London Interbank Offered Rate
LSE	Load-serving entity
LTIP	Long-Term Incentive Plan (including the PG&E Corporation 2021 Long-Term Incentive Plan and its predecessor, the PG&E Corporation 2014 Long-Term Incentive Plan)
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
MGMA	Microgrids Memorandum Account
MGP	manufactured gas plants
the Monitor	third-party monitor retained by the Utility as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAV	net asset value
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OEIS	Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OII	order instituting investigation
OIR	order instituting rulemaking
PCAOB	Public Company Accounting Oversight Board (United States)
PD	proposed decision
PERA	Public Employees Retirement Association
Petition Date	January 29, 2019
Plan	PG&E Corporation and the Utility, Knighthead Capital Management, LLC, and Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
POD	Presiding Officer’s Decision
PSPS	Public Safety Power Shutoff
QF	Qualifying facilities
RAMP	Risk Assessment Mitigation Phase

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RA	Resource Adequacy
ROE	return on equity
ROU asset	right-of-use asset
RPS	Renewables Portfolio Standard
RSA	restructuring support agreement
RTBA	Risk Transfer Balancing Account
RUBA	Residential Uncollectibles Balancing Account
SB	Senate Bill
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
SFGO	The Utility’s San Francisco General Office headquarters complex
ShareCo	PG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV	PG&E AR Facility, LLC
Tax Act	Tax Cuts and Jobs Act of 2017
TCC	Official Committee of Tort Claimants
TCC RSA	Restructuring Support Agreement dated December 6, 2019 with the TCC and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
VMBA	Vegetation Management Balancing Account
WEMA	Wildfire Expense Memorandum Account
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
WMBA	Wildfire Mitigation Balancing Account
WMCE	Wildfire Mitigation and Catastrophic Events
WMP	wildfire mitigation plan
WMPMA	Wildfire Mitigation Plan Memorandum Account
Zogg Complaint	The criminal complaint filed by the Shasta County District Attorney’s Office on September 24, 2021

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; forecasts of expense reduction; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, 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:

•the extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigates the risk of liability for damages arising from catastrophic wildfires, including whether the Utility maintains an approved WMP and a valid safety certification and whether the Wildfire Fund has sufficient remaining funds;

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•the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service territory, including the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), the wildfire that began on September 27, 2020 in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), the wildfire that began on July 13, 2021 near the Cresta Dam in the Feather River Canyon in Plumas County, California (the “2021 Dixie fire”), and any other wildfires for which the causes have yet to be determined; the damage caused by such wildfires; the extent of the Utility’s liability in connection with such wildfires (including the risk that the Utility may be found liable for damages regardless of fault); investigations into such wildfires, including those being conducted by the CPUC and various district attorney’s offices; the outcome of the criminal proceedings initiated against the Utility in connection with the 2019 Kincade fire, the 2020 Zogg fire, and three other fires; 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 in respect of any such fire; the risk that the Utility is not able to recover costs from insurance, from the Wildfire Fund or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations and proceedings;

•the extent to which the Utility’s wildfire mitigation initiatives are effective, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; and the cost of the program and the timing and outcome of any proceeding to recover such costs through rates;

•the impact of the Utility’s implementation of its PSPS program, and whether any fines, 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 costs through rates, and the effects on PG&E Corporation’s and the Utility’s reputations caused by implementation of the PSPS program;

•the Utility’s ability to safely, reliably, and efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably;

•the availability, cost, coverage, and terms of the Utility’s insurance, including insurance for wildfire, nuclear, and other liabilities, the timing of any insurance recoveries, and recovery of the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses through rates or from other third parties;

•significant changes to the electric power and gas industries driven by technological advancements and a decarbonized economy;

•cyber or physical attacks, including acts of terrorism, war, and vandalism, on the Utility or its third-party vendors, contractors, or customers (or others with whom they have shared data) which could result in operational disruption; the misappropriation or loss of confidential or proprietary assets, information or data, including customer, employee, financial, or operating system information, or intellectual property; corruption of data; or potential costs, lost revenues, or reputational harm incurred in connection therewith;

•the impact of severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, 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 effectiveness of the Utility’s efforts to prevent or respond to such conditions or events; 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 able to procure replacement power; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;

•the ability of the Utility to meet the conditions in its corrective action plan and exit the EOEP;

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•the timing and outcome of future regulation and federal, state or local legislation, their implementation, and their interpretation; the cost to comply with such regulation and legislation; and the extent to which the Utility recovers its associated compliance and investment costs, including those regarding:

◦wildfires, including inverse condemnation reform, wildfire insurance, and additional wildfire mitigation measures or other reforms targeted at the Utility or its industry;

◦the environment, including the costs incurred to discharge the Utility’s remediation obligations or the costs to comply with standards for GHG emissions, renewable energy targets, energy efficiency standards, distributed energy resources, and EVs;

◦the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, and cooling water intake, and the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

◦the regulation of utilities and their holding companies, including the conditions imposed on PG&E Corporation when it became the Utility’s holding company and whether the Utility can make distributions to PG&E Corporation; and

◦taxes and tax audits;

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested;

•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 projected 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;

•the outcome of current and future self-reports, investigations or other enforcement actions, or notices of violation that could be issued related to the Utility’s compliance with laws, rules, regulations, or orders applicable to its gas and electric operations; the construction, expansion, or replacement of its electric and gas facilities; electric grid reliability; audit, inspection and maintenance practices; customer billing and privacy; physical and cybersecurity protections; environmental laws and regulations; or otherwise, such as fines, penalties, remediation obligations, the transfer of ownership of the Utility’s assets to municipalities or other public entities, or the implementation of corporate governance, operational or other changes in connection with the EOEP;

•the risks and uncertainties associated with PG&E Corporation’s and the Utility’s substantial indebtedness and the limitations on their operating flexibility in the documents governing that indebtedness;

•the risks and uncertainties associated with the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing litigation, including appeals of the Confirmation Order; certain indemnity obligations to current and former officers and directors, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings; three purported class actions 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. 18-03509; the appeal of the 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 debarment proceeding; the purported PSPS class action filed in December 2019; and other third-party claims, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•the ability of PG&E Corporation and the Utility to securitize (i) the remaining $2.4 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility and (ii) $7.5 billion of costs related to the multiple wildfires that began on October 8, 2017 and 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”), in a financing transaction that is designed to be rate neutral to customers;

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•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;

•whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the IRC, as a result of which tax attributes could be limited;

•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 undergone by PG&E Corporation and the Utility in connection with their emergence from Chapter 11;

•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 that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs, DA providers and legislative mandates to replace gas-fuel technologies, have on the Utility’s ability to make and recover its investments through rates and earn its authorized ROE, 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 ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

•the risks and uncertainties associated with the Utility’s ability to accurately forecast major capital expenditures, weighted average annual rate base and expense reduction associated with implementation of the Lean operating system;

•the risks and uncertainties associated with rising rates for the Utility’s customers;

•actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings;

•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 receivables, the ability of the Utility to mitigate these effects, including with spending reductions, the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions caused either by illness of workers and their family members or workforce attrition related to potential new workplace regulations such as vaccine mandates;

•increased employee attrition as a result of the challenging political and operating environment facing PG&E Corporation and the Utility;

•whether PG&E Corporation’s and the Utility’s counterparties are available and able to meet their financial and performance obligations with respect to contracts, credit agreements, and financial instruments, which could be affected by disruptions in the global supply chain caused by the COVID-19 pandemic or otherwise; 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 7. 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.

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PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “Chapter 11,” “Wildfire and Safety Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. 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.

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PART I

ITEM 1. BUSINESS

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in Northern and Central California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility’s service area is shown in the graphic below.

PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found below in Item 8. Financial Statements and Supplementary Data.

The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000.

This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity, with distinct creditors and claimants, and is subject to separate laws, rules, and regulations.

Over the past several years, Northern California has experienced major wildfires. For more information about material wildfires, see Item 7. MD&A, and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

This 2021 Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these 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 and “Forward-Looking Statements” above.

Triple Bottom Line

PG&E Corporation’s and the Utility’s purpose is to deliver for their hometowns, serve the planet, and lead with love. In support of this purpose, the companies employ a Lean operating model designed to drive more effective and responsive decision-making, reduce the human struggle many coworkers face in their day-to-day work, and deliver better outcomes for customers and communities.

PG&E Corporation and the Utility measure their progress toward the purpose by considering their impact on the “triple bottom line” of people, planet, and prosperity, which is underpinned by performance; this consideration takes into account not only the economic value they create for customers and investors, but also their responsibility to social and environmental goals. The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities.

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PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions. The Utility will continue to seek fair and timely regulatory treatment in order to support its customer-driven investment plan while pursuing cost-control measures that would allow it to maintain the affordability of its service. The Lean operating system is an important means of realizing PG&E Corporation’s and the Utility’s objective of achieving world class performance while delivering hometown service.

People

The people element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to their workforce, their customers, the residents of local communities in which the companies do business, and other stakeholders.

PG&E Corporation’s and the Utility’s goal is to continually reduce risk to keep customers, the communities they serve, and their workforce (both employees and contractors) safe. Their focus is on continuously building an organization where every work activity is designed to facilitate safe performance, every worker knows and practices safe behaviors, and every individual is encouraged to speak up and stop work if they see unsafe or risky behavior, and has confidence that their concerns and ideas will be heard and pursued. PG&E Corporation and the Utility are committed to significantly improving their safety performance by understanding their risks, prioritizing their work, using controls to reduce risks, and continuously measuring and improving risk reduction.

PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility’s customer-driven investment program is aimed at improving safety, increasing electric and gas reliability, and improving customer satisfaction.

For more information, see “Human Capital” below.

Planet

The planet element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to protect and serve the environment. This commitment extends beyond compliance with various state and federal environmental, health, and safety laws and regulations. Management believes that integrating and managing climate change and other environmental considerations in the companies’ business strategies creates long-term value for PG&E Corporation and the Utility, and for their customers, communities, coworkers, and other stakeholders. Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility’s business and economic opportunity for the communities it serves.

The Utility strives to be prepared to continue to deliver safe, clean, affordable, and reliable energy in the face of increasingly severe and extreme climate-driven natural hazards. To build resilience to these hazards, the Utility is working to systematically integrate the consideration of forward-looking climate data and tools in its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate adaptation policy in California, and work directly with local governments and communities on adaptation solutions.

PG&E Corporation and the Utility are an important enabler of California’s effort to reduce GHG emissions. California has set a goal to achieve economy-wide carbon neutrality no later than 2045. SB 100 increased California’s RPS target to 60% by the end of 2030 and requires 100% of retail sales to come from eligible renewables or zero-carbon resources by the end of 2045.

The impacts of climate change on the Utility’s infrastructure are already a reality. Record-breaking extreme heat and heat waves are increasingly a regular occurrence throughout California. Peak loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage. The Utility’s assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine, and precipitation-related flooding because of climate-driven changes in precipitation and sea-level rise.

Climate change will also continue to intensify the potential for wildfires throughout California. The worsening conditions across California increase the likelihood and severity of wildfires, including those where the Utility’s equipment may be alleged to be associated with the fire’s ignition. Reducing risk will be even more important as climate change continues to exacerbate the risks facing the Utility. A key element of preparing the Utility for the physical risks of climate change is a system-wide CVA of the Utility’s assets, operations, and services, which the Utility expects to file with the CPUC in 2024. The CVA is expected to improve the Utility’s understanding of its exposure to climate hazards and the sensitivity of assets and operations to these hazards.

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The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California utilities also are experiencing increasing deployment by customers and third parties of distributed energy resources, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and load management technologies. These developments will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, and EV infrastructure. To this end, the CPUC is conducting proceedings to evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources and consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator.

PG&E Corporation and the Utility continue to pursue policies and programs that enable safe, reliable, and affordable clean and resilient energy for their customers. As a result of actions already taken by PG&E Corporation and the Utility, the companies have:

•Exceeded California’s renewable portfolio standards goal for each utility (including the Utility) to deliver 33 percent of eligible renewable energy by the end of 2020, and delivered clean electricity to customers in 2021 that was more than 90% GHG free.

•Helped customers avoid emissions through energy efficiency programs, supporting California’s goal to double energy efficiency in existing buildings by 2030.

•Awarded contracts for more than 1.7 GWs of battery energy storage, strengthening California’s grid efficiency and reliability.

•Installed approximately 5,000 charging ports for EVs at workplaces and multi-family dwellings, including installing 39% of these charging ports in disadvantaged communities, and also offered programs to support medium- and heavy-duty fleets and public fast charging in support of California’s goal of 100 percent sales of light-duty zero-emission vehicles by 2035.

•Brought the total number of interconnected private solar customers to more than 600,000 and supported more than 33,000 customers who have installed battery storage at their homes or businesses.

•Pursued decarbonization initiatives for the Utility’s natural gas delivery system, including working to interconnect several renewable natural gas projects.

Looking ahead, the Utility expects its GHG-free energy supply mix of renewable, large hydroelectric, and nuclear generation resources to remain elevated while Diablo Canyon continues to operate. Once Diablo Canyon ceases operations in 2025, the Utility expects its percentage of GHG-free electricity to decrease substantially. The CPUC coordinates the planning of supply resources through the Integrated Resource Planning (“IRP”) proceeding and has determined that replacing the power generated by Diablo Canyon is the responsibility of all LSEs within the CAISO. Towards the end of the decade and beyond, the Utility’s GHG-free energy supply mix is expected to grow relative to 2025 levels as the Utility works to meet California’s IRP GHG emissions reduction targets and its RPS target. For more information, see “Integrated Resource Planning Procurement” below.

Prosperity

The prosperity element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to meeting their financial objectives and providing economic development opportunities and benefits in the communities they serve. Management believes clean energy should be affordable for and inclusive of all economic backgrounds.

The Utility operates under a “cost of service ratemaking model,” which means that rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and have the opportunity to earn a return on invested capital. Under cost of service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs.

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In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). Revenue authorized by the CPUC through GRC proceedings is intended to provide the Utility a reasonable opportunity to recover its costs and earn a return on its investments in generation and distribution assets and general plant (also referred to as “rate base”) on a forecast basis. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administration and general expenses) and capital costs (e.g., depreciation, taxes, and financing expenses). In addition, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to “pass-through” to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Item 7. MD&A), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs.

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. The rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC and FERC proceedings.

Generally, differences between forecast costs and actual costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Results of Operations in Item 7. MD&A) can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials. Differences in costs can also arise from changes in laws and regulations at both the state and federal level. The Utility has initiated a program to reduce its spending on operations and maintenance.

PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing their debt. PG&E Corporation and the Utility have set goals to reduce their debt over time, including reducing PG&E Corporation’s debt by $2 billion by the end of 2023. PG&E Corporation and the Utility expect that reducing the consolidated debt will help them achieve investment grade credit ratings for their unsecured securities, for the benefit of both customers and investors. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8. Additionally, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. For more information, see “Application for Post-Emergence Securitization Transaction” in Item 7. MD&A.

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, as well as the Utility’s preferred stock. PG&E Corporation’s and the Utility’s ability to issue dividends is subject to restrictions. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock. For more information, see “Dividends” in Item 7. MD&A.

Total capital expenditures (including accruals) recorded in 2021 were $8.6 billion. The Utility’s total capital expenditures (including accruals) are forecasted to be between $7.8 billion and $8.9 billion for 2022, between $7.9 billion and $10.4 billion for 2023, between $7.9 billion and $10.7 billion for 2024, between $8.0 billion and $11.3 billion for 2025, and between $8.1 billion and $12.0 billion for 2026. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, community requests or protests, weather and other unforeseen conditions.

The Utility expects to make additional CPUC capital expenditures, the recovery of which will be subject to future regulatory approval, including the 2023 GRC. These expenditures include capital expenditures exceeding amounts authorized in the 2020 GRC, and expenditures to be included in a later stage of the 2023 GRC. The 2023 through 2026 currently above authorized capital spending levels are primarily for additional wildfire mitigation, transportation electrification and the Lakeside Building. Additionally, $3.21 billion of fire risk mitigation capital expenditures will be excluded from the Utility’s equity rate base pursuant to AB 1054.

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PG&E Corporation and the Utility are committed to keeping gas and electric services affordable for all customers. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, and the cumulative impact of other public policy requirements collectively place continuing upward pressure on customer rates. Certain CPUC proceedings, such as the OIR to Revisit Net Energy Metering Tariffs, could impact different types of customers differently. Similarly, although the Utility generally recovers its electricity and natural gas procurement costs through rates as “pass-through” costs, commodity prices rose substantially in 2021, relative to 2020. The Utility is addressing this customer rate pressure with cost reductions through increased efficiency, including efficiency driven by implementing the Lean operating system, improving its work management, identifying additional opportunities to convert expenses to capital expenditures, and an improved organizational design. The Utility has a number of programs in place to assist low-income customers, such as the CARE program. Under the CARE program, income-qualified customers can receive a monthly discount of 20% or more on their gas and electric bill.

PG&E Corporation’s and the Utility’s Corporate Sustainability Report, which is available to the public, describes the companies’ progress toward world-class performance measured with the triple bottom line framework.

In 2020, the Utility spent $3.9 billion with certified diverse suppliers, representing 38.9% of its total spend.

Performance: Underpinning The Triple Bottom Line

PG&E Corporation and the Utility are transitioning to the Lean operating system, which includes four basic “plays”: visual management, operating reviews, problem solving and standard work. PG&E Corporation and the Utility have implemented the first two plays in 2021 and expect to roll out the second two plays in 2022. Visual management allows teams to see how they are performing against their most important metrics using real-time data. During 2021, PG&E Corporation and the Utility have set up over 2,000 daily operating reviews, beginning with crews closest to the work and cascading up to senior leadership. These brief meetings help the Utility identify gaps and quickly develop plans to support the teams performing the work and give the Utility more visibility, control and predictability in its operations. For instance, the Lean operating system helped the Utility identify patterns in the conditions of ignitions and led to the implementation of EPSS. PG&E Corporation’s and the Utility’s performance is also driven by an increased focus on alignment on shared outcomes among its leadership and within the organization.

PG&E Corporation and the Utility have implemented a regional operating model to place more co-workers and operational leadership closer to their customers. The purposes of regionalization are to address local issues faster; reduce outage response times; create faster interconnections for customers connecting solar or distributed energy to the grid; and build stronger relationships and information flow between the companies and their customers.

California has experienced unprecedented weather conditions in recent years and the Utility’s service territory remains susceptible to additional wildfire activity. In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including:

•Enhanced Powerline Safety Settings: In 2021, the Utility implemented the EPSS program, which adjusts the sensitivity of circuit protection devices on certain power lines to de-energize them more rapidly in the event of a disturbance to help prevent potential ignitions. After EPSS was initiated, CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average.

•Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions. Since its inception in late 2017, the PSPS program has become more targeted because the Utility has developed more granular risk models, including adding consideration of vegetation management and maintenance tag statuses for scoping PSPS events. The Utility has also installed sectionalizers for more strategic de-energizations of circuits and transmission lines.

•Vegetation management: The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and clear vegetation that might grow or fall into utility equipment. In addition, the Utility operates an EVM program for distribution facilities in HFTD areas. The Utility is also increasing oversight and engagement with the contractors supporting vegetation management work.

•Asset inspections: Since 2018, the Utility has reoriented its asset inspections programs toward asset condition and consequence risk, particularly wildfire risk, and have become more thorough, standardized, digitized, and verifiable. The Utility uses risk-informed inspection cycles. In 2021, the Utility continued to refine its risk modeling, including further incorporating data from asset inspections.

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•System hardening: System hardening entails replacing or eliminating existing distribution lines in HFTDs and installing stronger and more resilient equipment. Hardening methods include replacing bare overhead conductor with covered conductor and installing stronger poles, removing the line and serving our customers through remote grids, or converting the line from overhead to underground. In 2021, the Utility announced a commitment to underground 10,000 miles of electric distribution lines in HFTDs, which will eliminate ignition risks from overhead vegetation or wind-induced equipment failures in those areas and help reduce the need for vegetation management.

Even as the Utility works to mitigate wildfire risk, it also works to reduce the impact of those mitigations on its customers, including making the PSPS program less disruptive through sectionalizing devices for both distribution and transmission lines, temporary generation applications, and implementation of microgrid pilot technologies. For example, in 2021, the CPUC authorized the Utility to prepare 10 substations to form microgrids in the event of PSPS outages impacting the transmission lines feeding those substations, in addition to nine other distribution microgrids that the Utility made ready to operate in 2021. Two of the distribution microgrids piloted battery storage and a linear generator in a hybrid configuration with diesel generation to assist in energizing the microgrids when needed. Through these and other mitigation actions, PSPS events in 2021 impacted 78% fewer customers on average than PSPS events in 2019. The Utility also brought online its first “remote grid” in 2021, which allows distribution lines in HFTDs to be removed and replaced with locally sited resources. Remote grids can reduce costs and fire risks, while maintaining service to impacted customers. The Utility is pursuing the development of additional remote grid projects.

In 2021, the Utility also worked to reduce the impact of EPSS by adjusting the sensitivity of devices to reduce the likelihood of an outage, improving coordination between its devices to reduce the size of outages, and improving internal coordination of patrol crews for faster restoration times. In 2022, the Utility plans to expand the scope of the EPSS program to all HFTD areas.

The Utility has focused on continuously improving its gas operations safety record. Since the San Bruno natural gas pipeline explosion in 2010, the Utility’s asset safety efforts have included replacing distribution mains and transmission pipelines, as well as strength testing transmission pipelines. The Utility uses in-line inspections to assess the integrity of transmission pipelines. The Utility also uses safety and control systems to monitor, gather, and process real-time data on its gas system. In 2021, the Utility’s gas operations achieved zero workforce serious injuries and fatalities (“SIF-A”) incidents and reductions in the number of injuries that result in days away, restricted or transferred duty per 200,000 hours worked (“DART”). As of the date of this filing, the Utility’s gas system has not had a public safety-related incident that resulted in a fatality or injury since 2015 or 2018, respectively.

The Utility has engaged in educating employees, contractors, and the public regarding safe digging programs and practices for their awareness during construction and when digging near the Utility’s underground gas and electric assets. The Utility also installed safety devices that automatically detect increasing pressure on systems and stop the flow of gas to avoid outages and overpressure events. Additionally, the Utility continues to streamline its efforts to respond to outages timely. The Utility’s outage response is designed to keep the public safe while limiting customer outages and returning service safely and as quickly as possible.

The Utility’s generation operations have focused on safety and reliability. In 2021, the Utility’s generation operations achieved zero SIF-A incidents and reductions in DART. Challenged by a drought year, the Utility scheduled dispatch and rescheduled outages to maximize availability during the summer months when demand for electricity is highest. The Utility is working to implement a comprehensive generation asset management strategy and further mature its outage and project management capabilities.

Regulatory Environment 

The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is regulated primarily by the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and OEIS.

This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility. For more information, see Item 1A. Risk Factors and “Regulatory Matters” in Item 7. MD&A.

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PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

California Public Utilities Commission

The CPUC is a regulatory agency that regulates privately owned public utilities in California. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transmission and storage services. The CPUC also has exercised jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electric and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

The CPUC enforces state laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities.  The CPUC can impose penalties of up to $100,000 per day, per violation. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged.

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation; but if it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued. Similar to penalties imposed by the CPUC, penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and may not be recovered in rates or otherwise directly or indirectly charged to customers. The CPUC has also authorized the SED to propose for CPUC approval administrative consent orders and administrative enforcement orders when the SED deems a formal OII unnecessary.

The California State Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to wildfires and wildfire cost recovery, increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, the establishment of energy storage procurement targets, and the development of a state-wide EV charging infrastructure. The CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs. The CPUC also conducts audits and reviews of the Utility’s accounting, performance, and compliance with regulatory guidelines.

The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. For more information on specific CPUC enforcement matters and CPUC-implemented laws and policies and the related impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Enforcement and Litigation Matters,” “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Federal Energy Regulatory Commission and California Independent System Operator Corporation

The FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas. The FERC regulates the interconnections of the Utility’s transmission systems with other electric systems and generation facilities, the tariffs and conditions of service of regional transmission organizations, and the terms and rates of wholesale electricity sales. The FERC also is charged with adopting and enforcing mandatory standards governing the reliability of the nation’s electric transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. The FERC’s approval is also required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property. The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations. For more information on specific FERC requirements and their impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

The CAISO is the FERC-approved regional transmission organization for the Utility’s service territory. The CAISO controls the operation of the electric transmission system in California and provides open access transmission service on a non-discriminatory basis. The CAISO is also responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generating capacity, ensuring that the reliability of the transmission system is maintained, and operating an interstate energy imbalance market.

Nuclear Regulatory Commission

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay. See “Electricity Resources” below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and substantial capital expenditures could be required in the future. For more information about Diablo Canyon, see Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Other Regulators

The California Energy Commission is California’s primary energy policy and planning agency. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans and for adopting building and appliance energy efficiency requirements.

The CARB is the state agency responsible for setting and monitoring GHG and other emission limits. The CARB is also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. See “Environmental Regulation - Air Quality and Climate Change” below.

The NTSB is an independent U.S. government investigative agency responsible for civil transportation accident investigations, including pipeline accidents. The NTSB also conducts special investigations and safety studies, and issues safety recommendations to prevent future accidents.

The California Geologic Energy Management Division is the state agency responsible for establishing and enforcing regulations for the operation of the Utility’s underground gas storage wells.

The OEIS is a state agency responsible for reviewing and approving the Utility’s WMP and for evaluating the Utility’s implementation of the WMP.

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In addition, the Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy or use public property for the operation of the Utility’s business and to conduct certain related operations. The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric and natural gas facilities in the public streets and highways. In exchange for the right to use public streets and highways, the Utility pays annual fees to the cities and counties. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. For more information see Item 1A. Risk Factors.

Third-party Monitors

On April 12, 2017, the Utility retained the Monitor at the Utility’s expense as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, which sentenced the Utility to, among other things, a five-year corporate probation period and oversight by the Monitor for a period of five years.  On January 25, 2022, the period of probation expired and the Monitor’s oversight of the Utility ended. For more information see Item 1A. Risk Factors and “US District Court Matters and Probation” under “Enforcement and Litigation Matters” in Item 7. MD&A.

Additionally, as a condition to its approval of the Plan, the CPUC required the appointment of an independent safety monitor (the “Independent Safety Monitor”) for a term of five years, subject to extension if the CPUC determines that the Utility’s safety conditions would benefit from an Independent Safety Monitor’s continued involvement. On January 28, 2022, the CPUC announced that it had selected Filsinger Energy Partners to serve as the Independent Safety Monitor. According to the scope of work authorized by the CPUC, the Independent Safety Monitor will (1) monitor and alert CPUC staff whether the Utility is implementing its highest priority and risk-driven safety mitigations and (2) monitor the Utility’s safety-related recordkeeping and record management systems. In addition to confidential updates to the CPUC staff regarding safety-related concerns, the Independent Safety Monitor will also provide public summary reports of its activities to the CPUC every six months.

Material Effects of Compliance with Governmental Regulations

As indicated above, the Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. Compliance with such extensive government regulations requires substantial expenditures and has had in the past and may continue to have in the future a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, cash flows and competitive position. Generally, the Utility expects to recover the cost of compliance with government regulations through rates in its GRC proceedings, or other proceedings. To the extent the Utility incurs costs above authorized or incurs additional types of costs not included in rates, the Utility would expect to apply for recovery of such costs. Such recovery would be subject to the CPUC’s approval and could involve its reasonableness review.

Costs incurred in 2021 included costs in connection with upgrading and maintaining the Utility’s electric and natural gas infrastructure in accordance with CPUC and federal requirements, participating in the Wildfire Fund under AB 1054, execution of wildfire mitigation initiatives, the licensing and other regulations of the FERC, environmental regulations, clean energy standards, regulations regarding Diablo Canyon, and various other generation, distribution and storage regulations, the amount of which was substantial.

If the Utility is unable to recover these costs or incurs fines or penalties as a result of non-compliance with such laws and regulations, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, cash flows and competitive position could be materially impacted. For more information, see Item 1A. Risk Factors, “Regulatory Matters” in Item 7. MD&A, and Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Environmental Regulation

The Utility’s operations are subject to extensive federal, state, and local laws and requirements 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 activities, including the remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of CO2 and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; and the environmental impacts of land use, including endangered species and habitat protection. The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. See Item 1A. Risk Factors. Generally, the Utility recovers most of the costs of complying with environmental laws and regulations through the Utility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a ratemaking mechanism described in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Waste Compliance and Remediation

The Utility’s facilities are subject to various regulations adopted by the EPA, including the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended. The Utility is also subject to the regulations adopted by other federal agencies responsible for implementing federal environmental laws. The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies. These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors. Under the Comprehensive Environmental Response, Compensation and Liability Act, these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, monitoring and paying for the harm caused to natural resources, and paying for the costs of health studies.

The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the California DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility has incurred significant environmental remediation liabilities associated with former MGP sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.

For more information about environmental remediation liabilities, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Air Quality and Climate Change

The Utility’s electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon dioxide (CO2), sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and other emissions.

Federal Regulation

At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions.

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Tackling the climate crisis is a key priority of the Biden Administration, and the Administration has signaled its intent to use its executive and regulatory authorities to reduce emissions in line with science-based targets. On January 20, 2021, President Biden issued an EO directing the EPA to consider suspending, revising or rescinding the Trump Administration’s rule for methane emissions from new sources in the oil and gas sector and propose a companion regulation for existing sources, including the transmission, processing and storage segments of the industry. For power plants, the EPA is expected to propose a more stringent GHG standard for existing sources in the wake of challenges to the Trump Administration’s Affordable Clean Energy rule.

State Regulation

California’s AB 32, the Global Warming Solutions Act of 2006, provided for the gradual reduction of state-wide GHG emissions to 1990 levels by 2020. The CARB has approved various regulations to achieve the 2020 target, including GHG emissions reporting and a state-wide, comprehensive cap-and-trade program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by major GHG emission sources within different sectors of the economy.

The cap-and-trade program’s first compliance period, which began on January 1, 2013, applied to the electric generation and large industrial sectors. In the subsequent compliance period, which began on January 1, 2015, the scope of the regulation was expanded to include the natural gas and transportation sectors, effectively covering all of the state economy’s major sectors through 2020. The Utility’s compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility’s customers other than large natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation.

In 2017, AB 398 extended the cap-and-trade program through January 1, 2031. During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Entities with a compliance obligation can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges. Complying entities may also satisfy a portion of their compliance obligation through the purchase of offset credits (e.g., credits for GHG reductions achieved by third parties, such as landowners, livestock owners, and farmers, that occur outside of the entities’ facilities through CARB-qualified offset projects such as reforestation or biomass projects). The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers.

SB 32 (2016) requires that CARB ensure a 40% reduction in GHGs by 2030 compared to 1990 levels. The California RPS program that requires utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California. In September 2018, SB 100 was signed into law, which accelerated California’s 50% RPS target to December 31, 2026, increased the RPS target to 60% by December 31, 2030, and further amended the RPS statute to set a policy of meeting 100% of retail sales from eligible renewables and zero-carbon resources by December 31, 2045. Additionally, EO B-55-18 set a statewide goal to achieve economy-wide carbon neutrality by 2045 and to maintain net negative emissions thereafter. The Utility will be an active participant in regulatory proceedings to determine how the state will achieve carbon neutrality. For the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2021, including estimated GHG-free and renewable energy percentages, see “Electric Utility Operations-Electricity Resources” below.

Climate Change Resilience Strategies

During 2021, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to take actions to increase its resilience to the physical impacts of climate change on the Utility’s operations. The Utility regularly reviews the most relevant scientific literature on climate change such as rising sea levels, major storm events, increasing temperatures and heatwaves, wildfires, drought and land subsidence, to help the Utility identify and evaluate climate change-related risks and develop resilience strategies. The Utility maintains emergency response plans and procedures to address a range of near-term risks, including wildfires, extreme storms, and heat waves and considers climate hazards in its risk-assessment process to account for long-term risks associated with climate change. The Utility also engages with leaders from business, government, academia, and non-profit organizations to share information and plan for the future.

The Utility is continuing its work to better understand the current and future impacts of climate change. Climate change is incorporated into the Utility’s Risk Assessment Mitigation Phase (“RAMP”) filing, which describes its quantitative risk modeling process and major risks. The Utility also considers the RAMP analysis in developing its infrastructure investment plans. Additionally, the Utility is conducting a system-wide CVA focused on 2050 to identify and help prioritize the Utility’s climate-driven hazards. Concurrent with the CVA are efforts to align key processes with the best available climate projections. For example, the Utility is currently reviewing and updating equipment design standards that rely on historically observed heat thresholds, which are not expected to be predictive of future temperatures.

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With respect to electric operations, climate scientists project that climate change will lead to increased electricity demand due to more extreme and frequent hot weather. The Utility believes its strategies to reduce GHG emissions through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage will help it adapt to the expected changes in demand for electricity. The Utility is making substantial investments to build a more resilient system that can better withstand extreme weather and related emergencies. For more information on such investments, see “Performance: Underpinning The Triple Bottom Line” above. Over the long term, the Utility also faces the risk of higher flooding and inundation potential at coastal and low elevation facilities due to projected sea level rise combined with high tides, storm runoff and storm surges. Inland areas, such as near the Sacramento-San Joaquin River Delta, will also be vulnerable to flooding amid changes to precipitation patterns and extreme storms. As the state continues to face increased risk of wildfires, the Utility’s wildfire mitigation activities, including vegetation management and undergrounding electric powerlines, will continue to play an important role to help reduce the risk of wildfire and its impact on electric and gas facilities.

Climate scientists predict that climate change will result in rising temperatures and changes in precipitation patterns in the Utility’s service territory, including decreasing snowpack. This could, in turn, affect the Utility’s hydroelectric generation. This issue is being analyzed as part of the Utility’s CVA. To plan for this change, the Utility is engaging with state and local stakeholders and is also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and collaborating on research and new modeling tools.

With respect to natural gas operations, both safety-related pipeline strength testing and normal pipeline maintenance and operations release the GHG methane into the atmosphere. The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression, which reduce the pressure and volume of natural gas within pipelines prior to venting.  In addition, the Utility continues to achieve reductions in methane emissions by implementing improvements in leak detection and repair, upgrades at metering and regulating stations, and maintenance and replacement of other pipeline materials. The Utility is also actively engaged with renewable natural gas producers to facilitate supply interconnections with the Utility’s natural gas pipeline system and is participating in CPUC proceedings that evaluate standards to allow for the injection of hydrogen into natural gas systems and decarbonization through electrification.

Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, the Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization. The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2020, which is the most recent data available, totaled more than 44 million metric tons of CO2 equivalent, the majority of which came from customer natural gas use. The following table shows the 2020 GHG emissions data the Utility reported to the CARB under AB 32, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Sustainability Report.

Source	Amount (metric tons CO2 equivalent)
Fossil Fuel-Fired Plants (1)	2,550,622
Natural Gas Compressor Stations and Storage Facilities (2)	315,802
Distribution Fugitive Natural Gas Emissions	497,512
Customer Natural Gas Use (3)	40,304,583

(1) Includes nitrous oxide and methane emissions from the Utility’s generating stations.

(2) Includes emissions from compressor stations and storage facilities that are reportable to CARB.

(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the exception of gas delivered to other natural gas local distribution companies.

The Utility utilized the CEC’s Power Source Disclosure program methodology to calculate the CO2 emissions rate associated with the electricity delivered to retail customers in 2020. This resulted in a third-party verified CO2 emissions rate of 160 pounds of CO2 per MWh.

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Air Emissions Data for Utility-Owned Generation

In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities. PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Sustainability Report.

	2020	2019
Total NOx Emissions (tons)	141	135
NOx Emissions Rate (pounds/MWh)	0.01	0.01
Total SO2 Emissions (tons)	15	14
SO2 Emissions Rate (pounds/MWh)	0.001	0.001

Nuclear Fuel Disposal

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities’ customers. The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay. As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel.

In September 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs.  The claim for the period June 1, 2020 through May 31, 2021, totaled approximately $11.6 million and is currently under review by the DOE.  Amounts reimbursed by DOE are refunded to customers through rates. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

Ratemaking Mechanisms

The Utility’s rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and a return on invested capital (“cost-of-service ratemaking”). In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administration and general expenses) and capital costs (e.g., depreciation, and financing expenses). In addition, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to “pass-through” to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Item 7. MD&A), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs.

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. The rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads.  Customer bills related to gas service are generally higher during winter months (November to March) because of higher demand due to heating.

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn some additional revenues. For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.

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See “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC proceedings.

Base Revenues

General Rate Cases

The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base. In the past, the CPUC has generally conducted a GRC every three years. Starting with the 2023 GRC, the CPUC will conduct a GRC every four years that includes the Utility’s costs of its gas transmission and storage facilities. The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). Attrition year rate adjustments are generally authorized for cost increases related to invested capital and inflation. Parties in the Utility’s GRC include the Public Advocates Office of the CPUC (formerly known as Office of Ratepayer Advocates or ORA) and TURN, which generally represent the overall interests of residential customers, as well as numerous intervenors, that represent other business, community, customer, environmental, and union interests. For more information about the Utility’s GRC, see “Regulatory Matters - 2020 General Rate Case” and “Regulatory Matters - 2023 General Rate Case” in Item 7. MD&A.

Cost of Capital Proceedings

The CPUC periodically conducts a cost of capital proceeding to authorize the Utility’s capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. The CPUC’s cost of capital proceedings generally take place in a consolidated proceeding with California’s other large investor-owned electric and gas utilities. For more information about the cost of capital proceedings, see “Regulatory Matters - Cost of Capital Proceedings” in Item 7. MD&A.

Electricity Transmission Owner Rate Cases

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. In its TO rate cases, the Utility uses a formula rate methodology, which includes an authorized revenue requirement and rate base for a given year but 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 are 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 are either collected from or refunded to customers. The FERC-approved formula rate will be effective through December 31, 2023. These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates and by the CAISO in its Transmission Access Charges to wholesale customers. For more information, see “Regulatory Matters - Transmission Owner Rate Cases” in Item 7. MD&A. The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations. These wholesale customers are charged individualized rates based on the terms of their contracts.

Program-Specific Memorandum Account and Balancing Account Costs

Periodically, costs arise outside of the CPUC GRC rate requests or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, new programs, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed reasonable. For instance, these accounts allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. Recovery of the costs tracked in these memorandum accounts in rates requires CPUC authorization in separate proceedings for which the Utility may be unable to predict the outcome. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts. The CPUC may authorize recovery of costs tracked in the balancing accounts on either a “one-way” basis, which only allows actual costs to be recovered up to a pre-established cap, or a “two-way” basis, which allows actual costs to be recovered, subject to CPUC review. For more information, see “Regulatory Matters - Cost Recovery Proceedings” in Item 7. MD&A and Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

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Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California IOUs are responsible for procuring electrical capacity required to meet bundled customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electric contracts. The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”). In addition, the utilities are required to obtain CPUC approval of their BPPs based on long-term demand forecasts. In October 2015, the CPUC approved the Utility’s most recent comprehensive BPP. It was revised since its initial approval and will remain in effect as revised until superseded by a subsequent CPUC-approved plan.

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved BPPs without further after-the-fact reasonableness review by the CPUC. The CPUC may disallow costs associated with electricity purchases if the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines that the utility failed to follow the principles of least-cost dispatch. Additionally, the CPUC may disallow the value of lost generation due to unplanned outages at utility-owned generation facilities.

The Utility recovers its electric procurement costs annually primarily through balancing accounts. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8. Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement. The CPUC may adjust the Utility’s retail electric rates more frequently if the forecasted aggregate over-collections or under-collections in the Energy Resource Recovery Account, net of Portfolio Allocation Balancing Account balances, exceed five percent of its prior year electric procurement and Utility-owned generation revenues. The CPUC performs an annual compliance review of the procurement transactions recovered in various balancing accounts, including the Energy Resource Recovery Account and the Portfolio Allocation Balancing Account.

The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved BPP, to meet mandatory renewable energy targets, and to comply with RA requirements. For more information, see “Electric Utility Operations - Electricity Resources” below as well as Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility is also responsible, as the central procurement entity (“CPE”) for its distribution service area, for seeking to procure the entire amount of required local RA on behalf of all load serving entities in its distribution service area. The decision grants the Utility, acting as CPE, discretion to defer procurement of local resources to the CAISO’s backstop mechanisms if bid costs are deemed unreasonably high. The Utility, as the CPE, will not be assessed fines or penalties for failing to procure resources to meet the local RA requirements and deferring local procurement to the CAISO backstop mechanism, as long as the CPE exercised reasonable efforts to secure capacity and certain specified requirements are met. In connection with its CPE function, the Utility is responsible for making compliance demonstrations to the CPUC and the CAISO. The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account. Each year, the CPUC reviews the Utility’s forecasted administrative costs related to the CPE function and approves a forecasted revenue requirement associated with the administrative costs. The CPUC performs an annual compliance review of the CPE function, including procurement transactions with terms of five years or less (for which costs incurred in compliance with certain prescribed criteria are deemed reasonable and pre-approved without further after-the-fact reasonableness review). Procurement transactions with terms exceeding five years are reviewed separately. The CPUC may disallow costs associated with the CPE function that were not incurred in compliance with the CPUC’s decisions and guidance.

The CPUC has also approved the Power Charge Indifference Adjustment (“PCIA”). The PCIA is a cost recovery mechanism to ensure that customers who switch from the Utility’s bundled service to a non-Utility provider, such as a DA or CCA provider, pay their share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf.

Natural Gas Procurement, Storage, and Transportation Costs

The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electric rates.

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The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its CPIM described below. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rate changes.

The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio. Under the CPIM, the Utility’s natural gas purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered through rates. One-half of the costs above 102% of the benchmark are recoverable through rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The Utility retains the remaining amount of these savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs. While this mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.

The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers. These providers transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements are governed by the FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. The FERC approves the United States tariffs that shippers, including the Utility, pay for pipeline service, and the applicable Canadian tariffs are approved by the National Energy Board, a Canadian regulatory agency. The transportation costs the Utility incurs under these agreements are recovered through CPUC-approved rates as core natural gas procurement costs or as a cost of electricity.

Costs Associated with Public Purpose and Customer Programs

The CPUC authorizes the Utility to recover the costs of various public purpose and other customer programs through the collection of rates from most Utility customers.  These programs relate to energy efficiency, demand response, distributed generation, energy research and development, and other matters.  Additionally, the CPUC has authorized the Utility to provide discounted rates for specified types of customers, such as for low-income customers under the CARE program, which is paid for by the Utility’s other customers.

Nuclear Decommissioning Costs

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. Nuclear decommissioning costs are generally collected in advance through rates and are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. The Utility files an application with the CPUC every three years requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear plants. If the nuclear decommissioning trusts are overfunded, the amount of such overfunding will be returned to customers. Pursuant to Public Utilities Code Section 8325, to the extent the monies available for decommissioning are insufficient to pay for all reasonable and prudent decommissioning costs, the CPUC must authorize the electric utility to collect these charges from its customers.

For costs related to AROs see “Nuclear Decommissioning Obligation” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

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Human Capital

Employees and Contractors

As of December 31, 2021, PG&E Corporation and the Utility had approximately 26,000 regular employees, 11 of whom were employees of PG&E Corporation. Of the Utility’s regular employees, approximately 16,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) IFPTE 20; and the Service Employees International Union Local 24/7 (“SEIU”). The collective bargaining agreements currently in effect for the IBEW Local 1245 and ESC Local 20 will expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits. The IBEW and ESC represent approximately 62% of the Utility’s employee workforce and support several areas of the Utility’s business, including gas and electric operations. The term of the SEIU bargaining agreement ended on December 31, 2021. The parties have reached an agreement which is pending ratification by the SEIU. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2021.

PG&E Corporation’s employees are primarily at the executive management level, which experienced significant employee turnover throughout the course of its Chapter 11 Cases in 2019 and 2020. The Utility generally has a stable workforce, which translated into low voluntary turnover during that period. The Utility’s turnover rates for 2021 and 2020 were 5.8% and 4.7%, respectively. Approximately 41% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, with an average tenure of 11 years. Currently, approximately 21% of PG&E Corporation’s and the Utility’s employees are eligible to retire. (PG&E Corporation and the Utility define retirement age as 55 years and older.)

The Utility’s contractors and subcontractors include approximately 35,300 individuals from approximately 1,560 contractor companies.

Human Capital Management

PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce. PG&E Corporation’s and the Utility’s Boards of Directors are responsible for overseeing management’s development and execution of PG&E Corporation’s and the Utility’s human capital strategy.

To build employee engagement, the Utility has a variety of both executive-level and employee-led initiatives and programs. PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and values that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity and inclusion, environmental leadership, and community service. The Utility conducts a biennial employee engagement survey, quarterly pulse surveys, and voluntary upward feedback surveys to measure and track employee engagement progress.

Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures. In addition, employees are required to complete an annual compliance and ethics training and a Code of Conduct training, both of which are intended to promote a culture in which employees are encouraged to speak up with any concerns or ideas for continuous improvement. In addition, the Utility offers a variety of other trainings and education opportunities.

Among other programs, the Utility provides career opportunities through its Power Pathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations. PowerPathway helps people throughout the Utility service territory, including women and military veterans, prepare and compete for high demand jobs in the utility and energy industry. Students receive approximately eight weeks of industry-informed curriculum to ensure the academic, job specific, employability skills and physical training necessary to effectively compete for entry-level employment. Programs may also include hands-on training and on-the-job training.

PG&E Corporation and the Utility also provide integrated solutions and programs that cover employee health and wellness and that encompass physical, emotional, and financial health, including an on-site health clinic, an annual health screening, and health management tools and resources, in addition to more traditional programs.

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PG&E Corporation’s and the Utility’s financial incentives offered to employees include a Short-Term Incentive Plan (“STIP”), an at-risk part of employee compensation designed to reward eligible employees for achieving specific performance goals. The 2021 STIP was focused on company objectives of safety, customer impact, and financial health.

All PG&E Corporation or Utility officer compensation currently is funded by shareholders.

Safety

The Utility has developed a five-year workforce safety strategy that includes two major pillars: systems and culture. Systems refers to risk management, equipment, processes and procedures. Culture refers to employee engagement, adherence to established requirements, a sense of urgency for safety, and leadership. Focus areas in the Utility’s workplace safety strategy include: an enterprise safety management system, enhanced risk management, strengthening the contractor management program, improvement of safety technical standards, ergonomics, safety audits, improving data management and reporting systems, and enhancing safety leadership training. For employees and contractors performing medium- and high-risk work, the Utility’s safety metrics include the number of SIF-A incidents and the SIF-P rate, which measures events that could have resulted in a SIF-A per 200,000 hours worked. In 2021, the Utility had five SIF-A events, which resulted in three fatalities and three serious injuries, and a SIF-P rate of 0.11, which was 10% higher than the SIF-P rate in 2020. The requirement for contractors to report SIF-P events was implemented in June 2020. Additionally, the Utility measures DART. In 2021, the Utility’s DART was 1.01, which was 25% lower than in 2020 and its lowest rate in the past five years.

Throughout the COVID-19 pandemic, PG&E Corporation and the Utility have continued to monitor activities at the Centers for Disease Control and Prevention and the World Health Organization, PG&E Corporation and the Utility have updated their protocols and actions in accordance with guidance from these organizations, following state and local health and safety regulations, and in consultation with the Utility’s medical director. PG&E Corporation and the Utility have also remained focused on protecting the health and safety of their employees, contractors and the Utility’s customers, while continuing to perform critical utility work, and have continued to monitor and track the impact of the pandemic, modifying or adopting new policies in support of their employees’ health and safety as pandemic conditions and governmental response have changed. For example, PG&E Corporation and the Utility have directed employees to work remotely from home where possible, implemented face coverings, physical distancing policies, and required a daily health check when an employee works outside his or her home, required virtual ergonomic evaluations to ensure that employees working from home so do safely and ergonomically, provided additional COVID-19 safety resources for employees who perform utility work in the field, and updated several of their employee benefits as a result of COVID-19, including healthcare benefits and interim time off and leave policies that support the care and new educational environment of children during the pandemic.

Diversity and Inclusion

PG&E Corporation’s and the Utility’s goal is to foster a diverse, equitable, and inclusive environment that enables all of their coworkers to bring their best selves to work so that they can provide exceptional customer service. These efforts are led by PG&E Corporation’s and the Utility’s Executive Vice President, People, Shared Services and Supply Chain, with support from the executive team. The People and Compensation Committee of PG&E Corporation’s Board of Directors reviews the companies’ diversity and inclusion practices and performance.

Key elements of PG&E Corporation’s and the Utility’s approach include active programming to heighten cultural competency, encourage understanding and appreciation of diversity, and integrate thoughtful content into training and performance support materials.

Additionally, the Utility’s 11 Employee Resource Groups and three Engineering Network Groups execute enterprise-wide programming, certain coworkers lead efforts within their departments, and other specialized teams facilitate dialogue across the companies. These efforts foster employee belonging and support an environment of inclusion that values and respects diversity in the workforce.

In 2021, women, minorities, and military veterans accounted for approximately 27%, 48% and 7%, respectively, of total PG&E Corporation and Utility employees. Approximately 8% of the Utility’s employees are younger than 30, 60% are between the ages of 30 and 49, and 32% are 50 or older.

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Electric Utility Operations

The Utility generates electricity and provides electric transmission and distribution services throughout its service territory in northern and central California to residential, commercial, industrial, and agricultural customers. The Utility provides “bundled” services (i.e., electricity, transmission, and distribution services) to customers in its service territory. Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations. For more information, see “Regulatory Matters” in Item 7. MD&A.

Electricity Resources

The Utility is required to maintain capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand.

The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2021 represented by each major electric resource, and further discussed below. The Utility’s deliveries were primarily from renewable energy resources that qualify under California’s RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California’s RPS requirements and SB 100 goal to serve 100% of retail electricity sales with GHG-free resources by 2045 are discussed further below and in the Environmental Regulation section above.

The total estimated electricity generated, procured, and sold (net), as of December 31, 2021 was 33,149 GWh (1) and comprised of the following:

	Percent of Bundled Retail Sales (estimated procurement)		CEC Reporting Methodology Adjustment(2)		Percent of Bundled Retail Sales (estimated Power Content Label) (2)
Owned Generation Facilities
Renewable (3)	2	%	—	%	2	%
Nuclear	39	%	—	%	39	%
Large Hydroelectric	4	%	—	%	4	%
Fossil fuel-fired (4)	19	%	(15)	%	4	%
Total	64	%	(15)	%	49	%
Third-Party Purchase Agreements
Renewable (3)	48	%	—	%	48	%
Large Hydroelectric	—	%	—	%	—	%
Fossil fuel-fired (4)	15	%	(12)	%	3	%
Total	63	%	(12)	%	51	%
Others, Net (2)(5)	(27)	%	27	%	—	%
TOTAL	100	%	—	%	100	%
Total Renewable Energy Resources (3)	50	%	—	%	50	%
GHG-Free Resources (6)	93	%	—	%	93	%

(1) This amount excludes electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.

(2) The allocation of “Others, Net” in the “CEC Reporting Methodology Reduction” and “Power Content Label” columns is consistent with CEC guidelines, applied to specified electric generation and procurement volumes (i.e., fossil fuel-fired, nuclear, large hydroelectric, and renewable). Total reported generation and procurement volumes equate to actual electric retail sales.

(3) Amounts include biopower (e.g., biogas, biomass), solar, wind, certain hydroelectric (i.e., 30MW or less), and geothermal facilities.

(4) Amounts consist primarily of natural gas facilities.

(5) Amount is mainly comprised of net CAISO open market (sales)/purchases.

(6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold.

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Renewable Energy Resources

California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. SB 350 increased the amount of renewable energy that must be delivered by most LSEs, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period, to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period, and in each three-year compliance period thereafter, unless changed by legislative action. SB 350 provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods. In September 2018, the California Governor signed SB 100 into law, increasing from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets. The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.

Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. RPS requirements are based on procurement, which aligns with the methodology presented in the first column of the table above. Procurement from renewable energy sources was estimated as 50% in 2021.

The estimated total renewable deliveries as of December 31, 2021 shown above was 16,387 GWh and comprised of the following:

Type	Percent of Bundled Retail Sales (estimated procurement)(1) (2)
Biopower	4	%
Geothermal	5	%
RPS-Eligible Small Hydroelectric	2	%
Solar	28	%
Wind	11	%
Total	50	%

(1) Estimated renewable procurement amounts are expected to be consistent with Power Content Label reporting and adjustments, based on current CEC guidelines.

(2) Estimated renewable procurement percentages above and renewable compliance percentages are expected to be consistent; however, final RPS compliance reporting may result in some differences between the two percentages.

Energy Storage

Energy storage improves system reliability and supports California’s decarbonization goals by integrating increased levels of renewable energy. The CPUC has established a multi-year energy storage procurement framework, under which the Utility was required to procure 580 MW of qualifying storage capacity by the end of 2020, with all energy storage projects required to be operational by the end of 2024. As of December 31, 2021, the Utility was on track to meet its storage goals by the end of 2024.

Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023. In January 2022, the Utility also requested CPUC approval for another 1,600 MW of storage to be completed by the summer of 2024, which would bring the Utility’s total energy storage system capacity to more than 3,330 MW. Finally, the Utility expects to solicit 200 MW of long-duration storage, which is storage with at least eight hours of discharge capacity, in 2022 to have these resources online between 2026 and 2028.

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Owned Generation Facilities

At December 31, 2021, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:

Generation Type	County Location	Number of Units	Net Operating Capacity (MW)
Nuclear (1):
Diablo Canyon	San Luis Obispo	2	2,240
Hydroelectric (2):
Conventional	16 counties in northern and central California	100	2,648
Helms pumped storage	Fresno	3	1,212
Fossil fuel-fired:
Colusa Generating Station	Colusa	1	657
Gateway Generating Station	Contra Costa	1	580
Humboldt Bay Generating Station	Humboldt	10	163
Photovoltaic (3):	Various	13	152
Total		130	7,652

(1) The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2. The NRC operating licenses expire in 2024 and 2025, respectively. On January 11, 2018, the CPUC approved the Utility’s application to retire Unit 1 by 2024 and Unit 2 by 2025.

(2) The Utility’s hydroelectric system consists of 103 generating units at 64 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to the FERC’s licensing requirements), with license terms between 30 and 50 years.

(3) The Utility’s large photovoltaic facilities are Cantua solar station (20 MW), Five Points solar station (15 MW), Gates solar station (20 MW), Giffen solar station (10 MW), Guernsey solar station (20 MW), Huron solar station (20 MW ), Stroud solar station (20 MW), West Gates solar station (10 MW), and Westside solar station (15 MW). All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County.

Generation Resources from Third Parties

The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan. See “Ratemaking Mechanisms” above. For more information regarding the Utility’s power purchase agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Electricity Transmission

At December 31, 2021, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV. The Utility also operated 33 electric transmission substations with a capacity of approximately 70,000 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO.

Electricity Distribution

The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2021, approximately 25% are underground and approximately 75% are overhead), 67 transmission switching substations, and 753 distribution substations with a capacity of approximately 35,000 MVA. The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers.

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These distribution substations serve as the central hubs for the Utility’s electric distribution network. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution facilities to entities, such as municipal and other utilities, that resell the electricity. The Utility operates electric distribution control center facilities in Concord, Rocklin, and Fresno, California; these control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2019 to 2021 for electricity sold or delivered, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2021, 2020 or 2019.

	2021		2020		2019
Customers (average for the year)	5,539,969		5,498,044		5,457,101
Deliveries (in GWh) (1)	78,588		78,497		78,070
Revenues (in millions):
Residential	$	6,089	$	5,523	$	4,847
Commercial	5,042		4,722		4,756
Industrial	1,493		1,530		1,493
Agricultural	1,565		1,471		1,106
Public street and highway lighting	73		69		67
Other (2)	(84)		(130)		168
Subtotal	14,178		13,185		12,437
Regulatory balancing accounts (3)	953		673		303
Total operating revenues	$	15,131	$	13,858	$	12,740
Selected Statistics:
Average annual residential usage (kWh)	5,889		6,179		5,750
Average billed revenues per kWh:
Residential	$	0.2125	$	0.1852	$	0.1762
Commercial	0.1802		0.1730		0.1585
Industrial	0.1075		0.1085		0.1015
Agricultural	0.2104		0.2210		0.2172
Net plant investment per customer	$	9,199	$	8,889	$	8,375

(1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.

(2) This activity is primarily related to provisions for rate refunds and unbilled electric revenue, partially offset by other miscellaneous revenue items.

(3) These amounts represent revenues authorized to be billed.

Natural Gas Utility Operations 

The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service territory.  Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or non-utility third-party gas procurement service providers (referred to as “core transport agents”).  When core customers purchase gas supply from a core transport agent, the Utility continues to provide gas delivery, metering and billing services to customers.  When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service.  Currently, more than 96% of core customers, representing approximately 85% of the annual core market demand, receive bundled natural gas service from the Utility.

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The Utility generally does not provide procurement service to non-core customers, which must purchase their gas supplies from third-party suppliers, unless the customer is a natural gas-fired generation facility with which the Utility has a power purchase agreement that includes its generation fuel expense. The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers.  Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.  The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.

Natural Gas Supplies

The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility can also receive natural gas from fields in California. The Utility purchases natural gas to serve its core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have varied generally based on market conditions. During 2021, the Utility purchased approximately 302,000 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all of this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 43% of the total natural gas volume the Utility purchased during 2021.

Natural Gas System Assets

The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. At December 31, 2021, the Utility’s natural gas system consisted of approximately 43,800 miles of distribution pipelines, over 6,200 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one small station on its local transmission system that are used to move gas through the Utility’s pipelines. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems.

The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. interconnecting downstream with TransCanada Foothills Pipe Lines Ltd., B.C. System. The Foothills system interconnects at the border to the pipeline system owned by Gas Transmission Northwest, LLC, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility also has firm transportation agreements with Ruby Pipeline, LLC to transport natural gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border. Similarly, the Utility has a firm transportation agreement with Transwestern Pipeline Company, LLC to transport natural gas from supply points in the southwestern United States to interconnection points with the Utility’s natural gas transportation system in the area of California near Topock, Arizona. (For more information regarding the Utility’s natural gas transportation agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s gas transmission system.  In 2019, the CPUC approved the discontinuation, through closure or sale, of operations at two of the Utility’s owned and operated gas storage fields, Pleasant Creek and Los Medanos. The Utility expects to sell Pleasant Creek in 2022 in accordance with the CPUC’s final decision in the 2019 GT&S rate case. The Utility intends to retain the Los Medanos field to further support system supply reliability as proposed in the 2023 GRC. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later for withdrawal.  In addition, four independent storage operators are interconnected to the Utility’s Northern California gas transmission system.

In 2021, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools and continued its work on the final recommendation from the NTSB’s 2010-11 San Bruno investigation to hydrostatically test all high consequence pipeline mileage. The Utility currently plans to complete this NTSB recommendation by 2022 for remaining short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines.

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Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2019 through 2021 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2021, 2020 or 2019.

	2021		2020		2019
Customers (average for the year) (1)	4,563,747		4,545,700		4,518,209
Gas purchased (MMcf)	226,037		226,746		227,621
Average price of natural gas purchased	$	3.19	$	2.02	$	2.08
Bundled gas sales (MMcf):
Residential	162,205		162,682		162,876
Commercial	54,262		49,834		54,479
Total Bundled Gas Sales	216,467		212,516		217,355
Revenues (in millions):
Bundled gas sales:
Residential	$	2,759	$	2,517	$	2,325
Commercial	713		597		605
Other	140		61		123
Bundled gas revenues	3,612		3,175		3,053
Transportation service only revenue	1,346		1,211		1,249
Subtotal	4,958		4,386		4,302
Regulatory balancing accounts (2)	553		225		87
Total operating revenues	$	5,511	$	4,611	$	4,389
Selected Statistics:
Average annual residential usage (Mcf)	37		37		38
Average billed bundled gas sales revenues per Mcf:
Residential	$	16.54	$	15.09	$	13.88
Commercial	11.63		10.61		9.72
Net plant investment per customer	$	4,130	$	3,794	$	3,522

(1) These amounts include natural gas provided by core transport agents and CCAs that procure their own supplies of natural gas for their respective customers.

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

Competition

Trends in Market Demand and Competitive Conditions in the Electricity Industry

California law allows qualifying non-residential electric customers of IOUs to purchase electricity from energy service providers rather than from the utilities up to certain annual limits specified for each utility. This arrangement is known as DA. In 2018, the California legislature passed a bill to expand the annual statewide DA cap by 4,000 GWh and directed the CPUC to consider whether DA should be further expanded. In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents and businesses that do not affirmatively elect to continue to receive electricity generated or procured by a utility. In 2019, the CPUC issued an order implementing the 4,000 GWh increase for DA transactions, including an apportionment to the Utility’s service area of approximately 1,873 GWh.

On June 24, 2021, the CPUC adopted a decision further implementing the 2018 legislation. In that decision, the CPUC recommended against further legislative expansion of DA at this time. Although a CPUC staff report issued in September 2020 had recommended expanding DA at a rate of ten percent each year, the CPUC ultimately found that recent reliability events and the current integrated resource planning forecasted needs for additional generation prevented a need for further DA reopening. The CPUC found that expanded DA would result in further fragmentation of the electric market in California and raise electric system reliability concerns. Additionally, the CPUC based its recommendation in part on DA providers’ primary reliance on unspecified power sources, which it found may not support California’s climate goals.

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The Utility continues to provide transmission, distribution, metering, and billing services to DA customers at the election of their energy service provider. The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility. In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges intended to recover the generation-related costs that the Utility incurred on behalf of DA and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers. Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities.

The Utility is also impacted by the increasing viability of distributed generation and energy storage. The levels of self-generation of electricity by customers (primarily solar installations) and the use of customer NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, are increasing, putting upward rate pressure on remaining customers. New NEM customers are required to pay an interconnection fee, utilize time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. Significantly higher bills for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers or adopt self-generation technologies. See “Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE” in Item 1A. Risk Factors and “Regulatory Matters-OIR to Revisit Net Energy Metering Tariffs” in Item 7. MD&A.

Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers. Those entities may rely upon FERC open access tariffs and Utility infrastructure to deliver energy to them at wholesale rates for resale at retail to existing or potential new Utility customers. These entities may also seek to acquire the Utility’s transmission or distribution facilities through eminent domain for use in serving electricity at retail to existing or potential new Utility customers. During the Chapter 11 Cases, multiple entities communicated their interest in acquiring Utility assets through voluntary sales. It is also expected that some publicly-owned utilities will construct duplicate or new transmission or distribution facilities to serve existing or potential new Utility customers. In some instances, microgrid formation is a key factor in a community’s choice to engage governmental entities.

The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service territory through a competitive bidding process managed by the CAISO.

The effect of such types of retail competition generally is to reduce the number of utility customers, leading to a reduction in the Utility’s rate base.

For risks in connection with increasing competition, see Item 1A. Risk Factors.

Competition in the Natural Gas Industry

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The Utility also competes for storage services with other third-party storage providers, primarily in Northern California.

ITEM 1A. RISK FACTORS

PG&E Corporation’s and the Utility’s financial results can be affected by many factors, including estimates and assumptions used in the critical accounting estimates described in Item 7. MD&A, that can cause their actual financial results to differ materially from historical results or from anticipated future financial results.  The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with Item 7. MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this 2021 Form 10-K.  Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Risk Factors Summary

The following is a summary of the principal risks that could adversely affect our business, operations, and financial results. These risks are discussed more fully below.

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Risks related to wildfires, including risks related to:

•The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigates the risk of liability for damages arising from catastrophic wildfires;

•The 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire or future wildfires;

•Recovery of excess costs in connection with wildfires; and

•Implementation of wildfire mitigation initiatives.

Risks related to operations and information technology, including risks related to:

•The hazardous nature of the Utility’s electricity and natural gas operations;

•The Utility’s insurance coverage;

•Changes in the electric power and gas industries;

•A cyber incident, cyber security breach, severe natural event or physical attack; and

•The operation and decommissioning of the Utility’s nuclear generation facilities.

Risks related to environmental factors, including risks related to:

•Severe weather conditions, extended drought and climate change and events resulting from these conditions (including wildfires); and

•Extensive environmental laws.

Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to:

•The Enhanced Oversight and Enforcement Process;

•Legislative and regulatory developments;

•Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject; and

•Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its costs.

Risks related to the environment and financial condition, including risks related to:

•PG&E Corporation’s and the Utility’s substantial indebtedness;

•Restrictions in indebtedness documents;

•Appeals of the Confirmation Order;

•Potential additional dilution to holders of PG&E Corporation common stock;

•Any substantial sale of stock by existing stockholders;

•Ownership and transfer restrictions associated with PG&E Corporation common stock;

•Tax-related risks and uncertainties, including the grantor trust election for the Fire Victim Trust;

•Restrictions on PG&E Corporation’s and the Utility’s ability to issue dividends;

•PG&E Corporation’s reliance on dividends, distributions and other payments from the Utility;

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•Restrictions on shareholders ability to change the direction or management of PG&E Corporation;

•The COVID-19 pandemic; and

•Increased customer rates.

General risks, including related to:

•Attracting and maintaining a qualified workforce or prolonged labor disruptions.

Risks Related to Wildfires

The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.

If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the AB 1054 disallowance cap. Under AB 1054, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Wildfire Fund reimbursement and a reformed prudent manager standard. The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable 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 at the time the applicable wildfire ignited. In addition, if the Utility fails to maintain a valid safety certificate at the time a wildfire ignites, the initial burden of proof in a prudency proceeding shifts from intervenors to the Utility. The Utility will be required to reimburse amounts that are determined by the CPUC not to be just and reasonable. For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Furthermore, 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. If the Utility is unable to maintain an AB 1054 safety certification or if the Wildfire Fund is exhausted, the ineffectiveness of the Wildfire Fund could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Also, the Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054.

The costs of participating in the Wildfire Fund are expected to exceed $6.7 billion over the anticipated ten-year contribution period for the fund. The timing and amount of any potential charges associated with the Utility’s contributions would also depend on various factors. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.

PG&E Corporation and the Utility could be liable as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, or future wildfires.

Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2020 Zogg fire and the 2021 Dixie fire. Although PG&E Corporation and the Utility have recorded liabilities for probable losses in connection with these fires, these liability estimates correspond to the lower end of the range of reasonably estimable losses, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information.

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Although there are a number of unknown facts surrounding Cal Fire’s causation determinations of the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, the Utility could be subject to significant liability in excess of recoveries 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 have responded or are responding to document, data, and other information requests from the CPUC’s SED and law enforcement agencies that are investigating these wildfires. 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, the 2021 Dixie fire or other wildfires. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges in the Kincade Amended Complaint or the Zogg Complaint, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. In the event that the Utility were convicted of certain charges in the Kincade Amended Complaint or the Zogg Complaint, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with each of the Kincade Amended Complaint and the Zogg Complaint would materially exceed the $800 million and the $375 million aggregate liability that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses for the 2019 Kincade fire and 2020 Zogg fire civil claims, respectively. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

There have also been numerous other wildfires in the Utility’s service territory, of which the Utility has not been alleged or determined to be a cause. The Utility could be alleged or determined to be a cause of one or more of these wildfires.

Additionally, under the doctrine of inverse condemnation, courts have imposed liability 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, even if the utility is unable to recover these costs through rates. In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful. Plaintiffs have asserted and continue to assert the doctrine of inverse condemnation in lawsuits related to certain wildfires that occurred in the Utility’s service territory. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines. While the Utility currently continues to dispute the applicability of inverse condemnation to the Utility, there can be no assurance that the Utility will be successful in challenging the applicability of inverse condemnation in the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, or other litigation against PG&E Corporation or the Utility.

Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Despite significant investment in mitigation measures to improve infrastructure and manage vegetation, as well as implementation of de-energization strategies, the Utility may not be successful in mitigating the risk of future wildfires.

In addition, wildfires have had and, along with any future wildfires, could continue to have, adverse consequences on the Utility’s proceedings with the CPUC (including the Safety Culture OII) and the FERC, and future regulatory proceedings, including future applications with the OEIS 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 as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire or any future wildfires. For more information about the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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The Utility may be unable to recover all or a significant portion of its excess costs in connection with wildfires from insurance, through rates, or from the Wildfire Fund in a timely manner.

The Utility could incur substantial costs in excess of insurance coverage or amounts potentially available under the Wildfire Fund under AB 1054 in the future in connection with the 2019 Kincade fire, the 2020 Zogg fire and the 2021 Dixie fire. There can be no assurance that the Utility will be allowed to recover costs in excess of insurance or amounts potentially available under the Wildfire Fund under AB 1054 in the future either through FERC TO rates or as costs recorded to the WEMA, 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. The inability to recover all or a significant portion of costs in excess of insurance through rates or by collecting such rates 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. For more information on wildfire recovery risk, see “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above, “The Utility’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events and events resulting from these conditions (including wildfires), or may not be available at a reasonable cost, or available at all” below, and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility may not effectively implement its wildfire mitigation initiatives.

The Utility’s infrastructure is aging and poses risks to safety and system reliability. Although the Utility spends significant resources on initiatives designed to mitigate wildfire risks, there is no assurance that these initiatives will be successful or effective in reducing wildfire-related losses or that their costs will be fully recoverable through rates. The Utility will face a higher likelihood of catastrophic wildfires in its service territory if it cannot effectively implement these efforts and its WMPs. For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing and retaining contract workers it needs to fulfill its mitigation obligations under the WMPs. The CPUC may assess penalties on the Utility if it finds that the Utility has failed to substantially comply with its WMPs.

There can be no assurance that the Utility’s wildfire mitigation initiatives will be effective. For instance, a wildfire may be ignited and spread even in conditions that do not trigger proactive de-energization according to criteria for initiating a PSPS event. The Utility’s inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues. If the Utility’s wildfire mitigation initiatives are not effective, a wildfire could be ignited and spread.

The PSPS program has been subject to significant scrutiny and criticism by various stakeholders, including customers, regulators, and lawmakers. The Utility also is the subject of a class action litigation in connection with the 2019 PSPS events.

In addition, on a risk-informed basis, the Utility is making efforts to reduce the frequency and impacts of PSPS. The Utility may be subject to mandated changes to, or restrictions on, its operational practices, regulatory fines and penalties, claims for damages, and reputational harm if the Utility does not execute PSPS in compliance with applicable rules and regulations. The Utility establishes the criteria under which it implements PSPS in its territory. To the extent the Utility’s criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires, the Utility does not fully implement PSPS when criteria are met due to other overriding conditions or the Utility’s regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, the Utility will face a higher likelihood of catastrophic wildfires in its territory during high-risk weather conditions.

PG&E Corporation and the Utility cannot predict the timing and outcome of the various proceedings and litigation in connection with its wildfire mitigation initiatives. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings or other enforcement actions as well as to additional litigation and claims by customers as a result of the Utility’s implementation of its wildfire mitigation initiatives, which could result in fines, penalties, customer rebates or other payments. The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other wildfire mitigation initiatives or liability for damages) could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS and EPSS programs have had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS and EPSS events may increase these negative perceptions. For more information, see “Regulatory Matters” in Item 7. MD&A.

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Risks Related to Operations and Information Technology

The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks.

The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. above. The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities. In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives, and the CPUC approved retirement of Diablo Canyon by 2024 and 2025. For more information, see “The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire” below.

The Utility’s ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably is subject to numerous risks, many of which are beyond the Utility’s control, including those that arise from:

•the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption or other catastrophic events;

•an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow;

•the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;

•a prolonged statewide electrical black-out that results in damage to the Utility’s equipment or damage to property owned by customers or other third parties;

•the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees, contractors, or the public, environmental damage, or reputational damage;

•the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;

•the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built;

•the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion);

•inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages;

•operator or other human error;

•a motor vehicle or aviation incident involving a Utility vehicle or aircraft, respectively (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences;

•an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently;

•construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system;

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•the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and

•attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war. For more information, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event or physical attack” below.

The occurrence of any of these events could interrupt fuel supplies, affect demand for electricity or natural gas, cause unplanned outages or reduce generating output, damage the Utility’s assets or operations, damage the assets or operations of third parties on which the Utility relies, damage property owned by customers or others, and cause personal injury or death. As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties. Any of such incidents also could lead to significant claims against the Utility.

Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities, the Utility may have less control over contractors than its employees and may retain liability for the quality and completion of the contractor’s work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders. The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions.

Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. An uninsured loss 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’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events and events resulting from these conditions (including wildfires), or may not be available at a reasonable cost, or available at all.

As a result of the potential application to IOUs of a strict liability standard under the doctrine of inverse condemnation, past losses recorded by insurance companies, past wildfires and the risk of increased wildfires including as a result of climate change, the Utility may not be able to obtain sufficient insurance coverage in the future at a reasonable cost, or at all.

The Utility has experienced increased costs and difficulties in obtaining insurance coverage for wildfires and other risks that could arise from the Utility’s ordinary operations. PG&E Corporation, the Utility or its contractors and customers could continue to experience coverage reductions or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of the Utility’s insurance coverage, including losses arising from litigation. Uninsured losses and increases in the cost of insurance may not be recoverable through rates. A loss that is not fully insured or cannot be recovered through rates, and increased insurance costs that are not recoverable, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The electric power and gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy.

The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice and state climate policy supporting a decarbonized economy. California utilities also are experiencing increasing deployment by customers and third parties of distributed energy resources, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies. These developments will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid’s capacity, and interconnect distributed energy resources. In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and state infrastructure modernization (e.g., rail and water projects). If the Utility is unable to effectively adapt to these changes, its business model and its ability to execute on its strategy could be materially impacted.

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Various jurisdictions within California have enacted prohibitions or restrictions on use and consumption of natural gas, for example in buildings, that will reduce the use of natural gas. Reducing natural gas use could lead to a reduction in the gas customer base and a diminished need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful,” potentially causing substantial investment value of gas assets to be stranded (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which results in a reduction in associated rate recovery). However, while natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements. Inability by the Utility to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.

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

The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event, or physical attack.

The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks. Private and public entities, such as the North American Electric Reliability Corporation, and the U.S. federal government, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.

The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. In addition, the Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers. In addition, the Utility is increasingly being required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California’s electricity market related to grid modernization and customer choice. These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents or inadequate security measures. Any incidents or disruptions in the Utility’s information technology systems could impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.

The Utility and its third-party vendors have been subject to, and will likely continue to be subject to, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations. None of these breaches or attempts has individually or in the aggregate resulted in a security incident with a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which 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 maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no assurance that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable through rates.

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The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire.

The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to operation of the Diablo Canyon nuclear generation units as well as the storage, handling and disposal of spent nuclear fuel, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the Utility may be required under federal law to pay up to $275 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States.

On January 11, 2018, the CPUC approved the retirement of Diablo Canyon units by 2024 and 2025. However, the Utility continues to face public concern about the safety of nuclear generation and nuclear fuel. Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete. It is also possible that public pressure could grow leading to adverse changes in legislation, regulations, orders, or their interpretation. As a result, operations at the Utility’s two nuclear generation units at Diablo Canyon could cease before their respective licenses expire in 2024 and 2025. In such an instance, the Utility could be required to record a charge for the remaining amount of its unrecovered investment and such charge 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, in order to retain highly skilled personnel necessary to safely operate Diablo Canyon during the remaining years of operations, the Utility will incur costs in connection with (i) an employee retention program to ensure adequate staffing levels at Diablo Canyon, and (ii) an employee retraining and development program, to facilitate redeployment of a portion of Diablo Canyon personnel to the decommissioning project and elsewhere in the Utility. There can be no assurance that the Utility will be successful in retaining highly skilled personnel under its employee programs.

The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders. See “Regulatory Environment” in Item 1. Business above. If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions. The Utility may incur a material charge if it ceases operations at Diablo Canyon’s two nuclear generation units before their respective licenses expire in 2024 and 2025. As of December 31, 2021, the Utility’s unrecovered investment in Diablo Canyon was $1.16 billion.

The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. See “Asset Retirement Obligations” in Note 3 of the Notes to the Consolidated Financial Statement in Item 8. The Utility’s costs to decommission its nuclear facilities through nuclear decommissioning are subject to reasonableness review by the CPUC. The Utility will be responsible for any costs that the CPUC determines were not reasonably incurred. If the Utility’s actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

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Risks Related to Environmental Factors

Severe weather conditions, extended drought, and climate change could materially affect PG&E Corporation and the Utility.

Extreme weather, drought and shifting climate patterns have intensified the challenges associated with many of the other risks facing PG&E Corporation and the Utility, particularly wildfire management in California. The Utility’s service territory encompasses some of the most densely forested areas in California and, as a consequence, is subject to higher risk from vegetation-related ignition events than other California IOUs. Further, environmental extremes, such as drought conditions and extreme heat followed by periods of wet weather, can drive additional vegetation growth (which can then fuel fires) and influence both the likelihood and severity of extraordinary wildfire events. In particular, the risk posed by wildfires, including during the 2021 wildfire season, has increased in the Utility’s service area as a result of an ongoing extended period of drought, bark beetle infestations in the California forest and wildfire fuel increases due to rising temperatures and record rainfall following the drought, and strong wind events, among other environmental factors. As of December 31, 2021, more than 86% of California is experiencing severe to extreme drought. Moderate or severe drought conditions occur and can persist in virtually all of the Utility’s service territory. More than half of the Utility’s service area is in an HFTD. Contributing factors other than environmental can include local land use policies and historical forestry management practices. The combined effects of extreme weather and climate change also impact this risk. In January 2018, the CPUC approved a statewide fire-threat map that shows that approximately half of the Utility’s service territory is facing “elevated” or “extreme” fire danger. Approximately 25,000 circuit miles of the Utility’s nearly 81,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs.

Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events (including recent extreme heat events during the 2021 wildfire season), drought, earthquakes, lightning, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility. Any such event could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Any of such events also could lead to significant claims against the Utility. Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility’s practices or the failure of electric and other equipment of the Utility.

Further, the Utility has been studying the potential effects of climate change (increased severity and frequency of storm events, sea level rise, land subsidence, change in temperature extremes, changes in precipitation patterns and drought, and wildfire) on its assets, operations, and services, and the Utility is developing adaptation plans to set forth a strategy for those events and conditions that the Utility believes are most significant. Consequences of these climate-driven events may vary widely and could include increased stress on the energy supply network due to new patterns of demand, reduced hydroelectric output, physical damage to the Utility’s infrastructure, higher operational costs, and an increase in the number and duration of customer outages and safety consequences for both employees and customers. As a result, the Utility’s hydroelectric generation could change, and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits. In addition, climate hazards such as heatwaves, windstorms, and flooding caused by rising sea levels and extreme storms could damage the Utility’s facilities, including gas, generation, and electric transmission and distribution assets. The Utility could incur substantial costs to repair or replace facilities, restore service, or compensate customers and other third parties for damages or injuries. The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase. See “Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE” above.

Events or conditions caused by climate change could have a greater impact on the Utility’s operations than the Utility’s studies suggest and could result in lower revenues or increased expenses, or both. If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

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The Utility’s operations are subject to extensive environmental laws, and such laws could change.

The Utility’s operations are subject to extensive federal, state, and local environmental laws, regulations, and orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation of natural resources and wildlife. The Utility incurs significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations. The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. Although the Utility has recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations. Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions.

The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future, or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover through rates.

Some of the Utility’s environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance. See “Environmental Regulation” in Item 1. and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination, changes in estimated costs, and the extent to which actual remediation costs differ from recorded liabilities have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Risks Related to Other Enforcement Matters, Investigations, and Regulatory Proceedings

PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process.

The EOEP is a six-step process with potentially escalating CPUC oversight and enforcement measures based on specific “triggering events” identified for each of the six steps. If the Utility is placed into the EOEP, it will be subject to additional reporting requirements and additional monitoring and oversight by the CPUC. Higher steps of the process (steps 3 through 6) also contemplate additional enforcement mechanisms, including appointment of an independent third-party monitor, appointment of a chief restructuring officer, pursuit of the receivership remedy, and review of the Utility’s Certificate of Public Convenience and Necessity (i.e., its license to operate as a utility). The process contains provisions for the Utility to cure and exit the process if it can satisfy specific criteria. The EOEP states that the Utility should presumptively move through the steps of the process sequentially, but the CPUC may place the Utility into the appropriate step of the process upon occurrence of a specified triggering event.

On April 15, 2021, the CPUC placed the Utility into step 1 of the EOEP for failing to sufficiently prioritize clearing vegetation on its highest risk power lines as part of the 2020 WMP work. There can be no assurance regarding if or when the Utility will exit the EOEP, or whether the CPUC will initiate another step 1 proceeding or whether the CPUC will seek to move the Utility into a higher step of the process. See “Enforcement and Litigation Matters” in Item 7. MD&A.

PG&E Corporation and the Utility could be materially affected by legislative and regulatory developments.

The Utility is subject to extensive regulations. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Wildfire Fund does not effectively mitigate the financial risk of liability for damages arising from catastrophic wildfires where the Utility’s facilities are a substantial cause. See “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.” above.

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In June 2018, the State of California enacted the CCPA, which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. The State of California announced enacted regulations in August 2020 and March 2021 which provide guidance on the requirements of the CCPA. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that creates the California Privacy Rights Act (the “CPRA”), which amended and expanded the CCPA. The State of California enacted the CPRA in November 2020, with most provisions operative as of January 1, 2023 and applicable to personal information collected beginning January 1, 2022. Failure to comply with the CCPA and the CPRA could result in the imposition of material fines imposed on PG&E Corporation and the Utility.

Also, SB 100 (the 100 Percent Clean Energy Act of 2018) increased the percentage from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from renewable portfolio standard-eligible or carbon-free resources by 2045. Failure to comply with SB 100 could result in fines imposed on PG&E Corporation and the Utility that could be material.

The Utility is subject to extensive regulations and the risk of enforcement proceedings in connection with compliance with such regulations.

The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with the Safety Culture OII (as defined in “Order Instituting an Investigation into PG&E Corporation’s and the Utility’s Safety Culture” under “Enforcement and Litigation Matters” in Item 7. MD&A) and other matters that the CPUC’s SED may be investigating. The SED could launch investigations at any time on any issue it deems appropriate. In addition, OEIS has authority to approve and oversee compliance with the WMP.

The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state, or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and RA requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC GOs or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance. CPUC staff could also impose penalties on the Utility in the future in accordance with its authority under the gas and electric safety citation programs. The amount of such fines, penalties, or customer refunds 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 also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires. See “Risks Related to Wildfires,” above. The Utility is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.

If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties the amount of which could be substantial and, in the event of a judgment against the Utility, suffer further ongoing negative consequences. Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the Utility’s violations.

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The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors, including if the Utility is not able to manage its costs effectively.

The Utility’s financial results depend on its ability to earn a reasonable return on capital, including long-term debt and equity, and to recover costs from its customers, through the rates it charges its customers as approved by the CPUC and the FERC. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility or if the amount of actual costs incurred differs from the forecast or authorized costs embedded in rates. The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility’s regulators, consumer and other stakeholder organizations, and customers, about the Utility’s ability to provide safe, reliable, and affordable electric and gas services. If the CPUC does not authorize sufficient funding for investments in the Utility’s infrastructure, it may negatively impact the Utility's ability to modernize the grid and make it resilient to risks related to climate change, including wildfires.

In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility’s actual costs differ from authorized or forecast costs. The Utility’s ability to recover its costs and earn a reasonable rate of return can be affected by many factors, including the time delay between when costs are incurred and when those costs are recovered through rates. The CPUC or the FERC may not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, the Utility may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs. For example, the Utility has incurred, and continues to incur, costs to strengthen its wildfire mitigation and prevention efforts before it is clear whether such costs will be recoverable through rates. Also, the CPUC may deny recovery of uninsured wildfire- related costs incurred by the Utility if the CPUC determines that the Utility was not prudent.

The Utility may incur additional costs or reduced revenue for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting the Utility’s operations), increased self-generation by customers, an increase in distributed generation, lower customer demand due to adverse economic conditions, the loss of the Utility’s customers to other retail providers like CCAs or DA providers, whether the CAISO wholesale electricity market continues to function effectively, returning customers, or compliance with new state laws or policies. See “Competition in the Electricity Industry” in Item 1.

Risks Related to PG&E Corporation’s and the Utility’s Environment and Financial Condition

PG&E Corporation’s and the Utility’s substantial indebtedness may adversely affect their financial health and operating flexibility.

PG&E Corporation and the Utility have a substantial amount of indebtedness, most of which is secured by liens on certain assets of PG&E Corporation and the Utility. As of December 31, 2021, PG&E Corporation had approximately $4.71 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $1.0 billion aggregate principal amount of senior secured notes due 2028, $1.0 billion aggregate principal amount of senior secured notes due 2030, and borrowings under the $2.75 billion secured term loan agreement entered into in June 2020), and the Utility had approximately $38.3 billion of outstanding indebtedness (such indebtedness including outstanding First Mortgage Bonds, borrowings under the Utility Revolving Credit Agreement and borrowings under the Utility Term Loan Credit Agreement). In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $1.4 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 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;

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•limiting their ability to use operating cash flow in other areas of their business;

•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. As a capital-intensive company, the Utility relies on access to the capital markets. If the Utility were unable to access the capital markets or the cost of financing were to substantially increase, its financial condition, results of operations, liquidity, and cash flows could be materially affected. The Utility’s ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including the Utility’s levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, and other market conditions. The Utility’s inability to service its substantial debt or access the financial markets on reasonable terms could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The documents that govern PG&E Corporation’s and the Utility’s indebtedness limit their flexibility in operating their business.

PG&E Corporation’s and the Utility’s material financing agreements, including certain of their respective credit agreements and indentures, contain various covenants restricting, among other things, their ability to:

•incur or assume indebtedness or guarantees of indebtedness;

•incur or assume liens;

•sell or dispose of all or substantially all of its property or business;

•merge or consolidate with other companies;

•enter into any sale leaseback transactions; and

•enter into swap agreements.

The restrictions contained in these material financing agreements could affect PG&E Corporation’s and the Utility’s ability to operate their business and may limit their ability to react to market conditions or take advantage of potential business opportunities as they arise. For example, such restrictions could adversely affect PG&E Corporation’s and the Utility’s ability to finance their operations and expenditures, make strategic acquisitions, investments or alliances, sell assets, restructure their organization or finance their capital needs. Additionally, PG&E Corporation’s and the Utility’s ability to comply with these covenants and restrictions may be affected by events beyond their control, including prevailing regulatory, economic, financial and industry conditions.

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. While a number of such appeals have been dismissed, there can be no assurance that any of the remaining appeals 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.

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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, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.

On the Emergence 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 14 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction 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 Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence 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.

Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8). Such payment may have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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.

Certain stockholders, including the Fire Victim Trust, received a large number of shares in the Chapter 11 Cases and may continue to hold 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 of 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.

PG&E Corporation may also sell additional shares of common stock in subsequent offerings or issue additional shares of common stock or securities convertible into shares of PG&E Corporation common stock. The issuance of any shares of PG&E Corporation common stock in future financings, acquisitions upon conversion or exercise of convertible securities, or otherwise may result in a reduction of the book value and market price of PG&E Corporation's outstanding common stock. If PG&E Corporation issues any such additional shares, the issuance will cause a reduction in the proportionate ownership and voting power of all current shareholders. PG&E Corporation cannot predict the size of future issuances of shares of PG&E Corporation common stock or securities convertible into shares of PG&E Corporation common stock or, for any issuance, the effect, if any, that such future issuances will have on the market price of PG&E Corporation's common stock.

PG&E Corporation common stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation’s ability to use its net operating loss carryforwards and other tax attributes.

PG&E Corporation has incurred and may also continue to incur in connection with the Plan significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties. The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the “capital stock”) and other interests designated as “stock” of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the “Equity Securities,” and such restrictions on transferability and ownership, the “Ownership Restrictions”) in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation’s ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for federal income tax purposes. Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid.

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Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities. For more information, see “Because PG&E Corporation and the Utility have elected to treat the Fire Victim Trust as a grantor trust, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that could differ materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act” below. Any transferee receiving Equity Securities that would result in a violation of the Ownership Restrictions will not be recognized as a shareholder of PG&E Corporation or entitled to any rights of shareholders, including, without limitation, the right to vote and to receive dividends or distributions, whether liquidating or otherwise, in each case, with respect to the Equity Securities causing the violation.

The Ownership Restrictions remain in effect until the earliest of (i) the repeal, amendment, or modification of Section 382 (and any comparable successor provision) of the Internal Revenue Code, in a manner that renders the restrictions imposed by Section 382 of the Internal Revenue Code no longer applicable to PG&E Corporation, (ii) the beginning of a taxable year in which the Board of Directors of PG&E Corporation determines that no tax benefits attributable to net operating losses or other tax attributes are available, (iii) the date selected by the Board of Directors if it determines that the limitation amount imposed by Section 382 of the Internal Revenue Code as of such date in the event of an “ownership change” of PG&E Corporation (as defined in Section 382 of the Internal Revenue Code and Treasury Regulation Sections 1.1502-91 et seq.) would not be materially less than the net operating loss carryforwards or “net unrealized built-in loss” (within the meaning of Section 382 of the Internal Revenue Code and Treasury Regulation Sections 1.1502-91 et seq.) of PG&E Corporation, and (iv) the date selected by the Board of Directors if it determines that it is in the best interests of PG&E Corporation’s shareholders for the Ownership Restrictions to be removed or released. The Ownership Restrictions may also be waived by the Board of Directors on a case by case basis.

Because PG&E Corporation and the Utility have elected to treat the Fire Victim Trust as a grantor trust, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that could differ materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act.

The Plan contemplated that the Fire Victim Trust would be treated as a “qualified settlement fund” for U.S. federal and state 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 and state income tax purposes instead. On July 8, 2021, PG&E Corporation, the Utility, ShareCo, and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a grantor trust election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust.

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the Ownership Restrictions. See “Tax Matters” in Item 7. MD&A for an example of these calculations. PG&E Corporation does not control the number of shares held by the Fire Victim Trust and is not able to determine in advance the number of shares the Fire Victim Trust will hold. PG&E Corporation intends to periodically make available to investors information about the number of shares of common stock held by the Fire Victim Trust, the Utility, and ShareCo as of a specified date for purposes of the Ownership Restrictions, including in its Quarterly Reports and Annual Reports filed with the SEC.

PG&E Corporation intends to enforce the Ownership Restrictions as described in the foregoing paragraph (calculated as excluding any shares owned by the Fire Victim Trust, the Utility, and ShareCo from the number of outstanding equity securities). All current and prospective shareholders are advised to consider the foregoing in determining their ownership and acquisition of PG&E Corporation common stock.

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PG&E Corporation may not be able to use some or all of its net operating loss carryforwards and other tax attributes to offset future income.

As of December 31, 2021, 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 $21.1 billion and $18.9 billion, respectively, and PG&E Corporation incurred and may also continue to 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 five percent 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).

As of the date of this report, it is more likely than not that PG&E Corporation has not 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 PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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. In addition, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to a successful rate-neutral securitization transaction 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.

PG&E Corporation’s ability to pay dividends on shares of its common stock is subject to restrictions.

Pursuant to the Confirmation Order, 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 Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items.

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.

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PG&E Corporation is a holding company and relies on dividends, distributions and other payments, advances, and transfers of funds from the Utility to meet its obligations.

PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility. Accordingly, PG&E Corporation’s cash flow and its ability to meet its debt service obligations under its existing and future indebtedness are largely dependent upon the earnings and cash flows of the Utility and the distribution or other payment of these earnings and cash flows to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances from the Utility. The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and may be restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in the agreements of those subsidiaries. Additionally, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and to meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation. 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. As of January 31, 2022, there were $59.1 million of such cumulative and unpaid dividends on the Utility’s preferred stock. In addition, the CPUC has imposed various conditions that govern the relationship between PG&E Corporation and the Utility, including financial conditions that require the Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. It is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock. The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to meet its obligations.

California law and certain provisions in the Amended Articles and the amended and restated bylaws of PG&E Corporation (the “Amended Bylaws”) may prevent efforts by shareholders to change the direction or management of PG&E Corporation.

The Amended Articles and the Amended Bylaws contain provisions that may make the acquisition of PG&E Corporation more difficult without the approval of the Board of Directors, including the following:

•until 2024, the Board of Directors will be divided into two equal classes, with members of each class elected in different years for different terms;

•only holders of shares who are entitled to cast ten percent or more of the votes can request a special meeting of the shareholders, and any such request must satisfy the requirements specified in the Amended Bylaws; action by shareholders may otherwise only be taken at an annual or special meeting duly called by or at the direction of a majority of the Board of Directors, or action by written consent signed by shareholders owning at least the number of votes necessary to authorize the action at a meeting where all shares entitled to vote were present;

•advance notice for all shareholder proposals is required; and

•any person acquiring PG&E Corporation Equity Securities will be restricted from owning 4.75% or more of such Equity Securities (as determined for federal income tax purposes (see “Tax Matters” in Item 7. MD&A)), subject to certain exceptions as may be determined by the Board of Directors of PG&E Corporation.

These and other provisions in the Amended Articles, the Amended Bylaws, and California law could make it more difficult for shareholders or potential acquirers to obtain control of the Board of Directors or initiate actions that are opposed by the then-current Board of Directors, including delaying or impeding merger, tender offer, or proxy contest involving PG&E Corporation. The existence of these provisions could negatively affect the price of PG&E Corporation common stock and limit opportunities for shareholders to realize value in a corporate transaction.

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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 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 the COVID-19 pandemic (and its variants), but the extent of such impact is uncertain.

PG&E Corporation and the Utility continue to evaluate the impact of the current COVID-19 outbreak on their business and financial results. The consequences of a continued and prolonged outbreak and resulting governmental and regulatory orders have had and could continue to have a negative impact on the Utility’s financial condition, results of operations, liquidity, and cash flows.

The outbreak of the COVID-19 pandemic and the resulting economic conditions, 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 resulted in a reduction in customer receipts and collection delays throughout the COVID-19 pandemic.

The Utility’s accounts receivable balances over 30 days outstanding as of December 31, 2021 were approximately $1.1 billion, or $832 million higher as compared to the balances as of December 31, 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 for as long as current COVID-19 circumstances persist.

On January 1, 2021, electric rates were reset using sales that were adjusted for the COVID-19 pandemic impacts and significant ongoing shortfalls are not currently expected in 2021. 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 ultimate 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. Increased governmental regulation of the COVID-19 pandemic protections, including vaccination mandates or testing requirement for workers, could result in employee attrition, workforce disruptions and increased supplier and contractor costs.

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.

The Utility has experienced shortages in certain materials, longer lead times and delivery delays as a result of domestic and international raw material and labor shortages. If these disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of the COVID-19 pandemic. Potential longer-term impacts of the COVID-19 pandemic on PG&E Corporation or the Utility include the potential for higher credit spreads, borrowing costs and incremental financing needs. PG&E Corporation’s and the Utility’s analysis of the potential impact of the COVID-19 pandemic is ongoing and subject to change. PG&E Corporation and the Utility are unable to predict the timing, duration or intensity of the COVID-19 pandemic situation and any resurgence of the COVID-19 pandemic and any variant strains of the COVID-19 virus, the effectiveness and intensity of measures to contain the COVID-19 pandemic (including availability and effectiveness of vaccines), and the effects of the COVID-19 situation on the business, financial condition and results of operations of PG&E Corporation and the Utility and on the business and general economic conditions in the State of California and the United States of America.

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Rising rates for the Utility’s customers could result in circumstances in which the Utility is unable to fully recover costs or earn its authorized ROE.

The rates paid by the Utility’s customers are impacted by the Utility’s costs, commodity prices, and broader energy trends. The Utility’s capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. In particular, the Utility will need to make substantial, sustained investments to its infrastructure to adapt to climate change. For more information on factors that could cause the Utility’s costs to increase, see “The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors, including if the Utility is not able to manage its costs effectively” above. If customer rates increase, the CPUC may face greater pressure to approve lesser amounts in the Utility’s ratemaking or cost recovery proceedings.

The Utility generally recovers its electricity and natural gas procurement costs through rates as “pass-through” costs. Increases in the Utility’s commodity costs directly impact customer bills.

Increasing levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, shifts costs to other customers. Under this structure, NEM customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, while still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. These unpaid costs are subsidized by customers not participating in NEM. Accordingly, as more electric customers switch to NEM and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing non-NEM customers.

Other long-term trends could also increase costs for gas customers. Natural gas providers are subject to compliance with CARB’s cap-and-trade program, and natural gas end-use customers have an increasing exposure to carbon costs under the program through 2030 (when the full cost will be reflected in customer bills). CARB may also require aggressive energy efficiency programs to reduce natural gas end use. Increased renewable portfolio standards generation in the electric sector could reduce electric generation gas load. Additionally, customers replacing natural gas appliances with electric appliances will lead to further reduced gas demand. The combination of reduced load and increased costs to maintain the gas system could result in higher natural gas customer bills. In addition, some local city governments have passed ordinances restricting use of natural gas in new construction and, if other jurisdictions follow suit, this could affect future demand for the provision of natural gas. If fewer customers receive gas from the Utility, the Utility’s gas system maintenance costs, many of which cannot be reduced in the short term even if gas quantities decrease, would be borne by fewer customers. Finally, a potential mandate to purchase renewable natural gas for core customers could lead to cost recovery risk if utilities are competing with the transportation sector without receiving the same incentives.

A confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility’s bundled electric service which could further reduce energy demand. Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could increase the energy rates for other customers.

If rates were to rise too rapidly, customer usage could decline. This decline would decrease the volume of sales, among which the Utility’s fixed costs are allocated, and increase rates.

To relieve some of this upward rate pressure, the CPUC may authorize lower revenues than the Utility requested or increase the period over which the Utility is allowed to recover amounts, which could impact the Utility’s ability to timely recover its operating costs. The Utility’s level of authorized capital investment could decline as well, leading to a slower growth in rate base and earnings. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

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General Risk Factors

The Utility may be unable to attract and retain qualified personnel and senior management talent, or prolonged labor disruptions may occur.

The Utility’s workforce is aging, and many employees are or will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may be faced with a shortage of experienced and qualified personnel. The majority of the Utility’s employees are covered by collective bargaining agreements with three unions. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of these agreements with the unions or if tentative new agreements are not ratified by their members. In addition, some of the remaining non-represented Utility employees could join one of these unions in the future.

PG&E Corporation and the Utility also may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the ongoing enforcement proceedings and the Chapter 11 Cases. Any such occurrences could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. For more information about labor disruptions related to the COVID-19 pandemic, see “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 the COVID-19 pandemic” above.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The Utility owns or has obtained the right to occupy or use real property comprising the Utility’s electricity and natural gas distribution facilities, electric generation facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, which are described in Item 1. Business, under “Electric Utility Operations” and “Natural Gas Utility Operations.” The Utility occupies or uses real property primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. In total, the Utility occupies 9 million square feet of real property, including 7 million square feet owned by the Utility. On September 17, 2021, the sale of the SFGO closed and the Utility entered into a leaseback agreement with the new SFGO owner (the “Leaseback Agreement”) to lease back certain space within the SFGO to allow for additional time to relocate critical facilities to other Utility sites. The Leaseback Agreement commenced on September 17, 2021 and continues through various dates for the various leased spaces, with December 31, 2023 being the latest lease expiration date. On October 23, 2020, the Utility entered into an office lease agreement with BA2 300 Lakeside LLC for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters. The term of the lease will begin on or about April 8, 2022 and the lease grants the Utility an option to purchase the legal parcel that contains the Lakeside Building. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation also leases approximately 42,000 square feet of office space from a third party in San Francisco, California. This lease will expire and be surrendered at the end of February 2022.

The Utility currently owns approximately 148,000 acres of land, including approximately 121,000 acres of watershed lands. In 2002, the Utility agreed to implement its Land Conservation Commitment (“LCC”) to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 40,000 acres of the watershed lands available for donation to qualified organizations. The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. The Utility’s goal is to implement all the LCC transactions by the end of 2023, subject to securing all required regulatory approvals.

ITEM 3. LEGAL 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 material lawsuits and proceedings, see “Enforcement and Litigation Matters” in Item 7. MD&A, Item 1A. Risk Factors and Notes 2, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable. 

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following individuals serve as executive officers of PG&E Corporation, as of February 10, 2022. Except as otherwise noted, all positions have been held at PG&E Corporation.

Name	Age	Positions Held Over Last Five Years	Time in Position
Patricia K. Poppe	53	Chief Executive Officer	January 4, 2021 to present
		President and Chief Executive Officer, CMS Energy Corporation	July 2016 to December 2020
		Vice President, Customer Experience, Rates and Regulations, Consumers Energy Company	January 2011 to July 2016
Christopher A. Foster	43	Executive Vice President and Chief Financial Officer	March 24, 2021 to present
		Vice President and Interim Chief Financial Officer	September 26, 2020 to March 23, 2021
		Vice President, Treasury and Investor Relations	March 9, 2020 to September 25, 2020
		Senior positions within PG&E Corporation’s Investor Relations department, including as its Vice President starting in December 2018	November 2017 to March 8, 2020
		Senior positions within PG&E Corporation and the Utility, including Director, Integrated Grid Planning and Innovation from June 2016 to October 2017	September 2011 to October 2017
Carla J. Peterman	43	Executive Vice President, Corporate Affairs and Chief Sustainability Officer	June 1, 2021 to present
		Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison	September 2019 to May 2021
		Commissioner, California Public Utilities Commission	December 2012 to December 2018
Julius Cox	50	Executive Vice President, People, Shared Services and Supply Chain, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to present
		Senior Vice President & Chief Human Resources Officer, American Electric Power	October 2019 to January 2021
		Executive Vice President & Chief Transformation Officer, Dynegy Inc.	September 2017 to April 2018
		Executive Vice President & Chief Administrative Officer, Dynegy Inc.	October 2014 to September 2017
Ajay Waghray	60	Senior Vice President and Chief Information Officer	September 21, 2020 to present
		Founder, Agni Growth Ventures, LLC	January 2019 to September 2021
		Executive Vice President and Chief Technology Officer, Assurant Inc.	May 2016 to December 2018
Sumeet Singh	43	Executive Vice President, Chief Risk Officer and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2022 to present

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		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to December 31, 2021
		Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation	January 1, 2021 to January 31, 2021
		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	August 2020 to December 31, 2021
		Gas Safety & Integrity Officer, Energy, Picarro, Inc.	February 2020 to August 2020
		Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018	September 2015 to January 2020
John R. Simon	57	Executive Vice President, General Counsel and Chief Ethics & Compliance Officer	August 15, 2020 to present
		Executive Vice President, Law, Strategy, and Policy	June 2019 to August 2020
		Executive Vice President	May 2019 to June 2019
		Interim Chief Executive Officer	January 2019 to May 2019
		Executive Vice President and General Counsel	March 2017 to January 2019
		Executive Vice President, Corporate Services and Human Resources	August 2015 to February 2017
Adam L. Wright	44	Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company	February 1, 2021 to present
		Chief Executive Officer and President, MidAmerican Energy Company	January 2018 to January 26, 2021
		President of MidAmerican Funding LLC	January 2018 to January 26, 2021
		Vice President, Gas Delivery, MidAmerican Energy Company	May 2015 to January 2018
		Vice President, Wind Generation & Development, MidAmerican Energy Company	January 2012 to May 2015
Marlene M. Santos	61	Executive Vice President and Chief Customer Officer, Pacific Gas and Electric Company	March 15, 2021 to present
		President, Gulf Power Company	January 2019 to March 2021
		Chief Integration Officer, NextEra Energy, Inc.	March 2015 to December 2018
Jason M. Glickman	41	Executive Vice President, Engineering, Planning, and Strategy, Pacific Gas and Electric Company	May 3, 2021 to present
		Global Head of Utilities and Renewables, Bain & Company	March 2020 to April 2021
		Partner, Bain & Company	January 2014 to April 2021
		Consultant, Bain & Company	August 2007 to December 2013

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The following individuals serve as executive officers of the Utility as of February 10, 2022. Except as otherwise noted, all positions have been held at the Utility.

Adam L. Wright	44	Executive Vice President, Operations and Chief Operating Officer	February 1, 2021 to present
		Chief Executive Officer and President, MidAmerican Energy Company	January 2018 to January 26, 2021
		President of MidAmerican Funding LLC	January 2018 to January 26, 2021
		Vice President, Gas Delivery, MidAmerican Energy Company	May 2015 to January 2018
		Vice President, Wind Generation & Development, MidAmerican Energy Company	January 2012 to May 2015
Marlene M. Santos	61	Executive Vice President and Chief Customer Officer	March 15, 2021 to present
		President, Gulf Power Company	January 2019 to March 2021
		Chief Integration Officer, NextEra Energy, Inc.	March 2015 to December 2018
Jason M. Glickman	41	Executive Vice President, Engineering, Planning, and Strategy	May 3, 2021 to present
		Global Head of Utilities and Renewables, Bain & Company	March 2020 to April 2021
		Partner, Bain & Company	January 2014 to April 2021
		Consultant, Bain & Company	August 2007 to December 2013
David S. Thomason	46	Vice President, Chief Financial Officer, and Controller, Pacific Gas and Electric Company	June 2016 to present
		Vice President and Controller, PG&E Corporation	June 2016 to present
		Senior Director, Financial Forecasting and Analysis	March 2015 to May 2016
		Senior Director, Corporate Accounting	March 2014 to March 2015
Julius Cox	50	Executive Vice President, People, Shared Services and Supply Chain, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to present
		Senior Vice President & Chief Human Resources Officer, American Electric Power	October 2019 to January 2021
		Executive Vice President & Chief Transformation Officer, Dynegy Inc.	September 2017 to April 2018
		Executive Vice President & Chief Administrative Officer, Dynegy Inc.	October 2014 to September 2017
Sumeet Singh	43	Executive Vice President, Chief Risk Officer and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company	January 1, 2022 to present
		Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	February 1, 2021 to December 31, 2021
		Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation	January 1, 2021 to January 31, 2021

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Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company	August 2020 to December 31, 2021
Gas Safety & Integrity Officer, Energy, Picarro, Inc.	February 2020 to August 2020
Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018	September 2015 to January 2020

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of February 4, 2022, there were 45,223 holders of record of PG&E Corporation common stock. A substantially greater number of holders of PG&E Corporation common stock are “street name” or beneficial holders, whose shares of record are held by banks, brokers, and other financial institutions. PG&E Corporation common stock is listed on the New York Stock Exchange and is traded under the symbol “PCG.” Shares of common stock of the Utility are wholly owned by PG&E Corporation. 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 February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. See “Liquidity and Financial Resources - Dividends” in Item 7. MD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 6 of the Notes to the Consolidated Financial Statements in Item 8. Information about the frequency and amount of dividends declared on preferred stock by the Utility appears in Note 7 of the Notes to the Consolidated Financial Statements in Item 8.

Sales of Unregistered Equity Securities

During the quarter ended December 31, 2021, PG&E Corporation did not make any equity contributions to the Utility. Also, PG&E Corporation did not make any sales of unregistered securities during the fiscal year ended December 31, 2021 that were not previously disclosed in a quarterly report on Form 10-Q or a current report on Form 8-K.

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2021, PG&E Corporation did not redeem or repurchase any shares of common stock or equity units outstanding. PG&E Corporation does not have any preferred stock outstanding. Also, during the quarter ended December 31, 2021, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

This is a combined report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net loss attributable to common shareholders was $102 million in 2021, compared to $1.3 billion in 2020. In the year ended December 31, 2021, PG&E Corporation recorded a $1.3 billion charge, net of tax as a result of the grantor trust election, with no similar amount in 2020. This amount is partially offset by increases in base revenues authorized in the 2020 GRC and previously deferred costs associated with various regulatory proceedings in the year ended December 31, 2021. In the year ended December 31, 2020, PG&E Corporation recognized $1.1 billion of expense related to the Backstop Commitment Premium Shares and $452 million of expense related to the Additional Backstop Premium Shares, with no similar amounts in 2021.

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Key Factors Affecting Financial Results

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

•The 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. The financial impact of future wildfires could be mitigated through insurance, the Wildfire Fund or other forms of cost recovery. However, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events, including coverage limitations applicable to different insurance layers. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any Wildfire Fund coverage year (“Coverage 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 is available to the Utility to pay eligible claims for liabilities arising from wildfires and serves 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 “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

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 therefore not subject to reimbursement, 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 allowed amount of such claims. See “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

•The Costs, Effectiveness, and Execution of the Utility’s Wildfire Mitigation Initiatives. 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 substantial expenditures in 2020 and 2021 in connection with the 2020-2022 WMP. For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8. The Utility expects that its wildfire mitigation initiatives will continue to involve substantial and ongoing expenditures. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain.

The Utility has implemented operational changes and investments that reduce wildfire risk, including the EPSS, PSPS, vegetation management, asset inspection, and system hardening programs. These programs, particularly the PSPS and EPSS programs, have been the subject of significant scrutiny and criticism by various stakeholders, including the California governor, the CPUC and the court that oversaw the Utility’s probation. The PSPS and EPSS programs have 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. See “OII to Examine the Late 2019 Public Safety Power Shutoff Events” in “Regulatory Matters” below.

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it is undertaking a review and has identified instances of noncompliance. The Utility intends to update the CPUC and OEIS as its review progresses. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for the late inspections or other noncompliance related to wildfire mitigation efforts. See “Self-Reports to the CPUC” in “Regulatory Matters” below.

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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. 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 “Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

•The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its FERC TO18 rate case and the resulting impact on the TO19 and TO20 rate cases, 2023 GRC, WMCE applications, 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, CPPMA, VMBA, WMBA, and RTBA. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 4 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below.

•The Impact of Wildfires. PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2020 Zogg fire, or the 2021 Dixie fire, are significant and may be excluded from any potential amounts recoverable under applicable insurance policies, the WEMA, FERC TO rates, or the Wildfire Fund under AB 1054. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. Liabilities in excess of recoverable amounts for these wildfires 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 December 31, 2021, PG&E Corporation and the Utility had recorded an aggregate liability of $800 million, $375 million, and $1.15 billion for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, respectively, and in each case before available insurance and other probable cost recoveries in the case of the 2021 Dixie fire. These liability amounts correspond to the lower end of the range of reasonably estimable probable losses, but do not include all categories of potential damages and losses. Claims related to the 2019 Kincade fire that were not satisfied in full as of the Emergence Date were not discharged in connection with emerging from Chapter 11.

On April 6, 2021, the Sonoma County District Attorney’s Office charged the Utility with five felonies and 28 misdemeanors in connection with the 2019 Kincade fire, and on January 28, 2022, the Sonoma County District Attorney’s Office filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors in connection with the 2020 Zogg fire and three other fires. If the Utility were to be convicted of certain charges in the Kincade Amended Complaint or the Zogg Complaint, the Utility could be subject to material fines, penalties, and restitution, as well as non-monetary remedies such as oversight requirements, and accordingly the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2019 Kincade fire or the 2020 Zogg fire would materially exceed the $800 million or $375 million, respectively, of aggregate liability that PG&E Corporation and the Utility have recorded.

If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, except that recoveries for the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy, and recoveries for each of these fires would also be subject to the other limitations and requirements under AB 1054. As of December 31, 2021, the Utility had recorded insurance receivables of $430 million for the 2019 Kincade fire, $337 million for the 2020 Zogg fire, and $563 million for the 2021 Dixie fire. The Utility had recorded regulatory recovery and Wildfire Fund receivables of $448 million and $150 million, respectively, for the 2021 Dixie fire. However, there can be no assurance that such amounts will ultimately be recovered, and the Utility does not expect that any of its liability insurance would cover restitution payments ordered by the courts presiding over the criminal proceedings. See “2019 Kincade Fire,” “2020 Zogg Fire,” and “2021 Dixie Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information.

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•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the Safety Culture OII, and potential penalties in connection with the Utility’s WMP and safety and other self-reports. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 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.

•The Uncertainties in Connection with the Enhanced Oversight and Enforcement Process. On April 15, 2021, the CPUC placed the Utility in step 1 of the EOEP. As a result, the Utility is subject to additional reporting requirements, monitoring, and oversight by the CPUC. See “Enhanced Oversight and Enforcement Process” in “Enforcement and Litigation Matters” below.

•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 the COVID-19 pandemic. 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, 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. PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19 pandemic. Other impacts of COVID-19 pandemic on PG&E Corporation and the Utility have included 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, higher credit spreads and borrowing costs and could potentially also include a reduction in revenue due to the cost of capital adjustment mechanism and incremental financing needs. For more information on the impact of COVID-19 pandemic 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 have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic.” in Item 1A Risk Factors and “COVID-19” in Liquidity and Financial Resources below.

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 addition, this annual 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 “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.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $21.1 billion and California net operating loss carryforward of $18.9 billion at the end of 2021.

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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 five percent 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 or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not 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.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a grantor trust election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust.

As a result of the benefits of a grantor trust election, the Utility’s tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation’s net operating loss has decreased by approximately $10.0 billion which will be offset by payments made by the Fire Victim Trust to the fire victims (which totaled approximately $1.67 billion in 2021) and the net activities of the Fire Victim Trust. Additionally, there was a $1.3 billion charge, net of tax, decreasing net DTAs for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Consolidated Financial Statements for activity through December 31, 2020. PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements for the year ended December 31, 2021. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares.

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

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,463,891,104 shares outstanding as of February 4, 2022, only 1,548,403,924 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2022 was 2.98% of outstanding shares. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares.

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RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2021, 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) available for common shareholders:

(in millions)	2021		2020		2019
Consolidated Total	$	(102)	$	(1,318)	$	(7,656)
PG&E Corporation	(226)		(1,715)		(20)
Utility	124		397		(7,636)

PG&E Corporation’s net loss decreased in 2021, as compared to 2020 and primarily consists of income taxes, interest expense on long-term debt, and reorganization items, net. PG&E Corporation’s net loss for the year ended December 31, 2020 included $1.5 billion in expense related to the Backstop Commitment Premium Shares and Additional Backstop Premium Shares, which is not deductible for tax purposes.

Utility

The table below shows certain items from the Utility’s Consolidated Statements of Income for 2021, 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.

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

	2021						2020						2019
	Revenues and Costs:						Revenues and Costs:						Revenues and Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	9,542	$	5,589	$	15,131	$	8,979	$	4,879	$	13,858	$	8,634	$	4,106	$	12,740
Natural gas operating revenues	3,753		1,758		5,511		3,460		1,151		4,611		3,259		1,130		4,389
Total operating revenues	13,295		7,347		20,642		12,439		6,030		18,469		11,893		5,236		17,129
Cost of electricity	—		3,232		3,232		—		3,116		3,116		—		3,095		3,095
Cost of natural gas	—		1,149		1,149		—		782		782		—		734		734
Operating and maintenance	6,820		3,374		10,194		6,399		2,308		8,707		7,167		1,583		8,750
Wildfire-related claims, net of insurance recoveries	258		—		258		251		—		251		11,435		—		11,435
Wildfire fund expense	517		—		517		413		—		413		—		—		—
Depreciation, amortization, and decommissioning	3,403		—		3,403		3,469		—		3,469		3,233		—		3,233
Total operating expenses	10,998		7,755		18,753		10,532		6,206		16,738		21,835		5,412		27,247
Operating income (loss)	2,297		(408)		1,889		1,907		(176)		1,731		(9,942)		(176)		(10,118)
Interest income	22		—		22		39		—		39		82		—		82
Interest expense	(1,373)		—		(1,373)		(1,111)		—		(1,111)		(912)		—		(912)
Other income, net	104		408		512		294		176		470		63		176		239
Reorganization items, net	(12)		—		(12)		(310)		—		(310)		(320)		—		(320)
Income (loss) before income taxes	$	1,038	$	—	$	1,038	$	819	$	—	$	819	$	(11,029)	$	—	$	(11,029)
Income tax provision (benefit) (1)					900						408						(3,407)
Net income (loss)					138						411						(7,622)
Preferred stock dividend requirement (1)					14						14						14
Income (loss) Attributable to Common Stock					$	124					$	397					$	(7,636)

(1) These items impacted earnings.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for 2021, 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 $856 million, or 7%, in 2021 compared to 2020, primarily due to increased base revenues authorized in the 2020 GRC and FERC formula rates.

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $546 million, or 5%, in 2020 compared to 2019, primarily due to increased base revenues authorized in the 2020 GRC and 2019 GT&S rate cases, additional revenues recorded pursuant to the TO20 rate case, and CEMA interim rate relief.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $421 million, or 7%, in 2021 compared to 2020, primarily due to increases in labor and insurance costs as well as a $135 million charge related to wildfire response and mitigation regulatory matters, including the 2020 WMCE settlement. These increases were partially offset by $298 million in previously deferred CEMA costs recorded in conjunction with interim rate relief in 2020, with no comparable costs in 2021.

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The Utility’s operating and maintenance expenses that impacted earnings decreased by $768 million, or 11%, in 2020 compared to 2019, primarily due to a reduction in accelerated transmission inspection and repair costs of approximately $460 million. Additionally, in 2019 the Utility recorded $398 million related to the Wildfires OII settlement and $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case in 2019, with no similar charges in 2020. These decreases were partially offset by an increase of $223 million in previously deferred CEMA costs recorded in conjunction with interim rate relief (see “2018 CEMA Application” below) (the Utility amortized $298 million in deferred CEMA costs in 2020, compared to $75 million amortized in 2019). The Utility also experienced increased insurance premium costs in the year ended December 31, 2020, compared to 2019.

Wildfire-Related Claims, Net of Recoveries

Costs related to wildfires that impacted earnings increased by $7 million, or 3%, in 2021 compared to 2020. The Utility recognized pre-tax charges of $1.15 billion related to the 2021 Dixie fire, offset by $563 million of probable insurance recoveries, $347 million of probable recoveries through the WEMA, and $150 million of probable recoveries from the Wildfire Fund in 2021, with no comparable charges and recoveries in 2020. The Utility recognized pre-tax charges of $175 million related to the 2019 Kincade fire in the year ended December 31, 2021, as compared to $625 million, partially offset by $430 million of probable insurance recoveries in the year ended December 31, 2020. Additionally, the Utility recognized pre-tax charges of $100 million related to the 2020 Zogg fire, fully offset by $100 million of probable insurance recoveries, in the year ended December 31, 2021, as compared to pre-tax charges of $275 million, partially offset by $219 million of probable insurance recoveries in the year ended December 31, 2020.

In addition to the probable wildfire-related recoveries noted above, in 2021, the Utility recorded $101 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims, which along with the items noted above, fully offset the $1.15 billion charge related to the 2021 Dixie fire.

Costs related to wildfires that impacted earnings decreased by $11.2 billion, or 98%, in 2020 compared to 2019. The Utility recognized pre-tax charges of $625 million related to the 2019 Kincade fire, partially offset by $430 million of probable insurance recoveries, and pre-tax charges of $275 million related to the 2020 Zogg fire, partially offset by $219 million of probable insurance recoveries in 2020. The Utility recognized charges of $11.4 billion in 2019, for wildfire-related claims primarily associated with the 2018 Camp fire and 2017 Northern California wildfires.

See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Wildfire Fund Expense

Wildfire fund expense that impacted earnings increased by $104 million, or 25%, in 2021 compared to 2020. Due to the Chapter 11 Cases, the Utility’s participation in the Wildfire Fund was limited to 40% for the period from July 12, 2019 to June 30, 2020. Additionally, the Utility recorded $43 million of accelerated amortization as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire.

Wildfire fund expense that impacted earnings increased by $413 million, or 100%, in 2020 compared to 2019. In 2020, the Utility became eligible to participate in the Wildfire Fund and as a result recorded amortization and accretion expense related to the Wildfire Fund coverage received from the effective date of AB 1054 through December 31, 2020.

See Notes 3 and 14 of the Notes to the Consolidated Financial Statements in Item 8.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses decreased by $66 million, or 2%, in 2021 compared to 2020, primarily due to a reduction in decommissioning expense that was recorded as a result of the final 2018 Nuclear Decommissioning Cost Triennial Proceeding decision.

The Utility’s depreciation, amortization, and decommissioning expenses increased by $236 million, or 7%, in 2020 compared to 2019, primarily due to capital additions and an increase in depreciation rates associated with the TO20 decision.

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Interest Income

The Utility’s interest income that impacted earnings decreased by $17 million, or 44%, in 2021 compared to 2020. Interest income decreased by $43 million, or 52%, in 2020 compared to 2019. The Utility’s interest income is primarily affected by changes in regulatory balancing accounts and changes in interest rates.

Interest Expense

Interest expense that impacted earnings increased by $262 million, or 24%, in 2021 compared to 2020, primarily due to the issuance of additional long-term debt.

The Utility’s interest expense that impacted earnings increased by $199 million, or 22%, in 2020 compared to 2019, primarily due to the issuance of new debt in 2020 in connection with the emergence from Chapter 11.

Other Income, Net

Changes to Other income, net that impact earnings are primarily driven by fluctuations in the balance of construction work in progress that impact equity AFUDC.

Reorganization Items, Net

Reorganization items, net that impacted earnings decreased by $298 million, or 96%, in 2021 compared to 2020, primarily due to the Utility’s emergence from the Chapter 11 Cases on July 1, 2020.

There was no material change to reorganization items, net that impacted earnings in 2020 compared to 2019.

Income Tax Provision (Benefit)

Income tax expense increased by $492 million in 2021 compared to 2020, primarily due to a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021, as compared to a smaller DTA write-off associated with the decline in value of PG&E Corporation common stock contributed into a Fire Victim Trust in the same period in 2020.

The Utility’s income tax benefit increased by $3.8 billion in 2020 compared to 2019, primarily due to a pre-tax loss in 2019 compared to pre-tax income in 2020. Additionally, there was a $619 million adjustment from the measurement of the DTA 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 in 2020. 

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

	2021		2020		2019
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	24.1	%	19.1	%	7.5	%
Effect of regulatory treatment of fixed asset differences (2)	(51.6)	%	(44.9)	%	2.8	%
Tax credits	(1.2)	%	(1.7)	%	0.1	%
Fire Victim Trust (3)	91.9	%	51.7	%	—	%
Bankruptcy and emergence	—	%	2.4	%	—	%
Other, net (4)	2.6	%	2.2	%	(0.5)	%
Effective tax rate	86.8	%	49.8	%	30.9	%

(1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election.

(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 2021 and 2020, 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 the effect of the grantor trust election as discussed in Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs in 2021 and 2020.

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), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs 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 10 of the Notes to the Consolidated Financial Statements in Item 8. 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.

(in millions)	2021		2020		2019
Cost of purchased power, net	$	2,883	$	2,854	$	2,809
Fuel used in own generation facilities	349		262		286
Total cost of electricity	$	3,232	$	3,116	$	3,095

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 10 of the Notes to the Consolidated Financial Statements in Item 8. 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. 

(in millions)	2021		2020		2019
Cost of natural gas sold	$	1,010	$	648	$	622
Transportation cost of natural gas sold	139		134		112
Total cost of natural gas	$	1,149	$	782	$	734

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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.  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

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 emergence 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 received from the Utility, and PG&E Corporation’s access to the capital and credit markets.

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. The collateral posting provisions for some of the Utility’s power and natural gas commodity, and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions. The Utility’s credit ratings fell below investment grade in January 2019, at which time the Utility was required to post additional collateral under its commodity purchase agreements. A further downgrade would not materially impact the collateral postings for procurement activity. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Recognition of Lease Assets and Liabilities” in Note 3, Note 5, Note 12, and “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

COVID-19

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 the COVID-19 pandemic. The outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus (including Delta and Omicron), and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have impacted and will continue to impact the Utility for an indeterminate period of time. 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 for eligible medium and large commercial and industrial customers that expired on September 30, 2021, the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” and an observed reduction in non-residential electrical load. The Utility’s accounts receivable balances over 30 days outstanding as of December 31, 2021, were approximately $1.1 billion, or $832 million higher as compared to the balance as of December 31, 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 for as long as current COVID-19 circumstances persist.

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On April 16, 2020, the CPUC adopted a resolution ordering utilities to implement a number of emergency customer protections, including a moratorium on service disconnections for residential and small business customers, beginning on March 4, 2020, which it subsequently extended through June 30, 2021. The CPUC authorized utilities to establish memorandum accounts to track incremental costs associated with complying with the resolution. On April 19, 2021, the CPUC issued a final decision to implement a temporary moratorium on service disconnection for medium and large commercial and industrial customers. Although the moratorium on service disconnections ended on September 30, 2021, the Utility does not anticipate resuming service disconnections until 2022. If the moratorium on service disconnections were to be reinstated, it could have a material impact on results of operations, financial condition, and cash flows of PG&E Corporation and the Utility.

Although the Utility is seeking further regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance as to the amount or timing of such relief. On July 16, 2021, the California governor signed into law AB 135, which provides financing assistance to customer accounts in arrears. See “Assembly Bill 135” below for more information. AB 135 allocates roughly $300 million in relief funding to the Utility’s customers and the amount was paid on January 27, 2022.

As of December 31, 2021, PG&E Corporation and the Utility had access to approximately $2.2 billion of total liquidity comprised of approximately $165 million of Utility cash, $126 million of PG&E Corporation cash and $1.9 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. See “Cost of Capital Proceedings” below for more information.

The Utility has established the CPPMA memorandum accounts for tracking costs related to the CPUC’s emergency authorization and order, which, as of December 31, 2021, totaled $49 million and is reflected in Long-term regulatory assets on the Consolidated Balance Sheets. In addition to the $49 million recorded to the CPPMA that is subject to CPUC approval, the Utility has recorded approximately $127 million of undercollections from residential customers from June 11, 2020 to December 31, 2021 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Consolidated Balance Sheets. During the quarter ended December 31, 2021, there was an adjustment to the RUBA current balancing accounts receivable of $180 million as a result of the expected CAPP funding, which was received on January 27, 2022. For more information on the impact of the COVID-19 pandemic 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 have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic” in Item 1A. Risk Factors in Part I of this 2021 Form 10-K.

The COVID-19 pandemic may continue to impact PG&E Corporation and the Utility financially, and PG&E Corporation and the Utility will continue to monitor the overall impact of the COVID-19 pandemic.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. 

Financial Resources

Equity Financings

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in “At the Market Equity Distribution Program” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in “At the Market Equity Distribution Program” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8) with the Forward Purchasers.

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As of December 31, 2021, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings. During the year ended December 31, 2021, PG&E Corporation has not sold any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement.

Debt Financings

In March 2021, the Utility issued (i) $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, (ii) $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and (iii) $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility Term Loan Credit Agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement, and (iii) general corporate purposes.

In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On November 15, 2021, the Utility completed the sale of (i) $300 million aggregate principal amount of Floating Rate First Mortgage Bonds due November 14, 2022, (ii) $900 million aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 and (iii) an additional $550 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 (the “2031 Bonds”). The 2031 Bonds are part of the same series of debt securities issued by the Utility in March 2021. The proceeds were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021. The Utility used the remaining net proceeds for general corporate purposes, including the repayment of approximately $300 million of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

For more information, see “Recovery Bonds” below and “Long-Term Debt” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

Credit Facilities

As of December 31, 2021, PG&E Corporation and the Utility had $500 million and $1.4 billion available under their respective $500 million and $6.4 billion credit facilities, including the Utility’s term loan credit facility and Receivables Securitization Program. The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time.

For more information, see “Credit Facilities” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. The intercompany note includes usual and customary provisions for notes of this type. The interest rate on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet.

Recovery Bonds

On November 12, 2021, PG&E Recovery Funding LLC, a bankruptcy remote, limited liability company wholly owned by the Utility, issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The net proceeds were used to fund fire risk mitigation capital expenditures that have been incurred by the Utility and incurred by PG&E Corporation on behalf of the Utility in 2020 and 2021.

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For more information, see “AB 1054” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

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 March 20, 2020, PG&E Corporation and the Utility filed a 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. As of January 31, 2022, there were $59.1 million of such cumulative and unpaid dividends on the Utility’s preferred stock. 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 emergence 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. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. It is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock.

Utility Cash Flows

The Utility’s cash flows were as follows:

	Year Ended December 31,
(in millions)	2021		2020		2019
Net cash provided by (used in) operating activities	$	2,448	$	(19,047)	$	4,810
Net cash used in investing activities	(7,050)		(7,748)		(6,378)
Net cash provided by financing activities	4,379		26,070		1,395
Net change in cash, cash equivalents, and restricted cash	$	(223)	$	(725)	$	(173)

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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 2021, net cash provided by operating activities increased by $21.5 billion compared to the same period in 2020.  This increase was primarily due to the payment of $18.8 billion in satisfaction of pre-petition wildfire-related claims in 2020 as compared to the payment of $758 million to the Fire Victim Trust in 2021. Additionally, the Utility made initial and first annual contributions to the Wildfire Fund of $5.2 billion during the year ended December 31, 2020 as compared to the $193 million contribution made during the year ended December 31, 2021. Lastly, the Utility paid approximately $260 million more in interest in satisfaction of pre-petition claims during the year ended December 31, 2020 as compared to 2021. The increase was partially offset by wildfire-related insurance reimbursements of $2.2 billion received in 2020 as compared to $0.1 billion in 2021.

During 2020, net cash provided by operating activities decreased by $23.9 billion compared to 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 the initial, first, and second annual contributions made to the Wildfire Fund of $5.2 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 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;

•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 “Wildfire-Related Securities Class Action” in Note 14 and “Enforcement Matters” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 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 through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing;

•the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires;

•the timing and amount of substantially increasing costs in connection with 2020-2022 WMPs and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

•the timing and amount of premium payments related to wildfire insurance (see “Insurance Coverage” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information);

•the timing of the gain to be returned to customers from the sale of the SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested.

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 under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Investing Activities

Net cash used in investing activities decreased by $698 million during 2021 as compared to the same period in 2020. The decrease was primarily due to the sale of the SFGO, which resulted in net proceeds received of $749 million in September 2021, with no similar receipts in 2020. See “Application to Sell General Office Complex” below for more information.

Net cash used in investing activities increased by $1.4 billion during 2020 as compared to 2019 partially due to the payment of pre-petition vendor payables for capital expenditures as a result of emerging from the Chapter 11 Cases. 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.

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 between $7.8 billion and $8.9 billion in 2022. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building.

Financing Activities

During 2021, net cash provided by financing activities decreased by $21.7 billion as compared to 2020. This decrease was primarily due to PG&E Corporation making a cash equity contribution to the Utility of approximately $13.0 billion in 2020, with no similar activity in 2021. Additionally, during 2021, the Utility issued approximately $3.3 billion less of long-term debt, net of repayments, as compared to the same period in 2020. In addition, the Utility had net borrowings of $4.6 billion under its credit facilities during the year ended December 31, 2020 as compared to net repayments of $246 million during the same period in 2021. The Utility had net borrowings of short-term debt of $1.4 billion during the year ended December 31, 2020, as compared to net repayments of short-term debt of $1.2 billion during the same period in 2021. The decrease was partially offset by $1.5 billion of net repayments of debtor-in-possession credit facilities in 2020, with no similar payments in 2021. Lastly, the Utility received $370 million of proceeds in 2021 in connection with the Transaction Agreement between the Utility and SBA, with no similar receipts in 2020. For more information, see “Sale of Transmission Tower Wireless Licenses” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

During 2020, net cash provided by financing activities increased by $24.7 billion as compared to 2019. This increase was primarily due to PG&E Corporation making a cash equity contribution to the Utility of approximately $13.0 billion, and the Utility receiving $10.4 billion in proceeds from the issuance of short-term and long-term first mortgage bonds, with no similar activities in 2019. Additionally, the Utility had net borrowings of $4.6 billion under its credit facilities during the year ended December 31, 2020, with no similar activity in 2019 due to the Utility entering into the facilities in 2020. These increases were partially offset by net repayments of $1.5 billion on the debtor-in-possession facilities in 2020, as compared to net borrowings of $1.5 billion on the debtor-in-possession facilities in 2019.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments.  Additionally, future cash flows from financing activities will be affected by the timing and outcome of the Utility’s applications for a post-emergence securitization transaction and for an AB 1054 securitization transaction. See “Application for Post-Emergence Securitization Transaction” and “Application for AB 1054 Securitization Transaction” below for more information. 

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 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8. that are incorporated by reference herein. 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.

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U.S. District Court Matters and Probation

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

In the course of 2021, the court entered numerous other orders, including in connection with the Utility’s vegetation management, the Utility’s PSPS program, the 2018 Camp fire, the 2019 Kincade fire, the 2020 Zogg fire and the 2021 Dixie fire.

On January 25, 2022, the period of probation expired and the Monitor’s oversight of the Utility ended.

Enhanced Oversight and Enforcement Process

In the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility’s operational performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics (some of which will be determined in an ongoing regulatory proceeding). The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The EOEP 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 EOEP requires the Utility to report the occurrence of a triggering event to the CPUC’s executive director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

The Utility is unable to predict whether additional fines or penalties may be imposed, or other regulatory actions may be taken.

On August 18, 2021, the President of the CPUC informed the Utility that the CPUC staff intends to conduct a fact-finding review regarding a pattern of self-reported missed inspections and other self-reported safety incidents to determine whether a recommendation to advance the Utility further within the EOEP is warranted.

Vegetation Management

The CPUC placed the Utility into step 1 of the EOEP on April 15, 2021 and imposed additional reporting requirements on the Utility. The CPUC’s resolution states that a step 1 triggering event had occurred because the Utility “has made insufficient progress toward approved safety or risk-driven investments related to its electric business.” The resolution finds that, based on the CPUC’s evaluation of the Utility’s EVM work in 2020, the Utility “is not sufficiently prioritizing its Enhanced Vegetation Management (“EVM”) based on risk” and “is not making risk-driven investments.” The resolution also finds that “less than five percent of the EVM work” the Utility completed in 2020 “was on the 20 highest risk power lines according to [its] own risk rankings.”

As required by the CPUC’s resolution, the Utility submitted a corrective action plan to the CPUC’s Executive Director on May 6, 2021, which is designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addresses the EVM situation that occurred in 2020 and provides a risk-informed EVM workplan for 2021. The Utility is required to update the information contained in the corrective action plan every 90 days. The Utility will remain in step 1 of the EOEP until the CPUC determines that the Utility has met the conditions of the corrective action plan. If the Utility does not adequately meet such conditions within the timeframe approved by the CPUC, the CPUC may place the Utility into a higher step of the EOEP, or the Utility may remain in step 1 of the EOEP if it demonstrates sufficient progress towards meeting such conditions.

The Utility is unable to predict the outcome of this regulatory process.

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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.

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 ROE to safety performance metrics.

On September 4, 2020, the administrative law judge 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.

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.

During 2021, the Utility continued to make progress on regulatory matters.

•In June, the Utility filed its 2023 GRC application. The application requests a revenue requirement of $15.46 billion for the 2023 test year.

•In August, the CPUC approved the Utility’s agreement to sell the SFGO. In September, the sale closed.

•In September, OEIS issued a final decision statement approving the Utility’s 2021 WMP, and in October the CPUC ratified the OEIS’ approval.

•In September, the Utility filed a motion seeking CPUC approval of a settlement agreement for its 2020 WMCE application. Under the settlement agreement, the Utility would recover a revenue requirement of $1.04 billion, or 81% of the requested $1.28 billion.

•In September, the Utility filed its 2021 WMCE application, requesting cost recovery of approximately $1.6 billion of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities, resulting in a proposed revenue requirement of approximately $1.47 billion.

•In October, the CPUC approved the settlement agreement among the Utility and other parties that authorizes the Utility to recover $445.5 million in incremental insurance costs in its WEMA that were incurred for the period of July 26, 2017 through December 31, 2019.

•In November, the Utility filed a motion seeking CPUC approval of a settlement agreement for its 2018 CEMA application. Under the settlement agreement, the Utility would recover approximately $683 million plus interest, compared to the requested $763 million.

In addition, on January 31, 2022, the OEIS issued the Utility’s 2021 safety certification, which will be valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later.

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Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC rate requests or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC also authorized balancing accounts with limitations or caps to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. As of December 31, 2021, the Utility had recorded an aggregate amount of approximately $5.4 billion in costs not otherwise being recovered in existing revenue requirements, if any, for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Because rate recovery may require CPUC authorization for these accounts, there is a delay between when the Utility incurs costs and when it may recover those costs.

If the amount of the costs recorded in these accounts continues to increase, the delay between incurring and recovering costs lengthens, or the Utility does not recover the full amount of its costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. 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 these applications.

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8., “Regulatory Matters - Wildfire Mitigation and Catastrophic Events Costs Recovery Applications,” “Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account,” and “Regulatory Matters - Catastrophic Event Memorandum Accounts and Applications” below.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2020 WMCE Application

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

The costs addressed in the 2020 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 Utility’s request includes amounts from the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

Given the CPUC’s prior approval of $447 million in interim rate relief (which includes interest), the Utility proposed 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, which could result in some or all of the interim rate relief being subject to refund.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement would authorize the Utility to continue to recover the interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this matter to April 1, 2022.

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2021 WMCE Application

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings. The majority of the Utility’s proposed revenue requirement would be collected over a two-year period starting in January 2023.

The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memo accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19.4 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery ask of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction is a result of identified avoided costs, such as employee business travel expenses and in-person training costs, due to the pandemic.

The scoping memo shows a schedule with the CPUC issuing a PD in the fourth quarter of 2022.

Wildfire Expense Memorandum Account Application

On February 7, 2020, the Utility filed an application requesting cost recovery of $499 million of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019, which were recorded in the WEMA. These costs are incremental to the insurance costs authorized in the 2017 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 the WEMA. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and the other active parties that authorizes the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022.

Catastrophic Event Memorandum Account Application

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. The Utility has historically sought such costs through standalone CEMA applications. More recently, the Utility has sought CEMA-eligible costs through its WMCE applications.

In addition to the Utility’s responsibilities in responding to catastrophic events, in 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. Through 2019, the costs associated with this work were tracked in the CEMA. In the 2020 GRC decision, the CPUC required the Utility to track these costs in the VMBA beginning January 1, 2020.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented, commencing on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund.

On November 2, 2021, the Utility filed with the CPUC a settlement agreement with the active parties in the matter. The settlement agreement, if approved by the CPUC, would authorize the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount has already been collected in interim rates. The interim rates would become final and no longer subject to refund. The remainder of the authorized revenue requirement that has yet to be collected would be amortized over a 12-month period.

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Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in proceedings to adjust its regulated return on rate base.

Decisions in GRC proceedings are generally expected prior to the commencement of the period to which the rates would apply. However, delayed decisions in the Utility’s GRCs may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the outcomes of these applications.

The Utility’s rate cases that are pending, have pending appeals, or were completed in 2021 are summarized in the following table:

Rate Case	Request	Status
2023 GRC	Revenue requirement of $15.28 billion for 2023	Filed June 2021. A decision on the initial track of the proceeding is expected in the second quarter of 2023.
2019 GT&S	Removal of $39.4 million of disallowance	Approved January 2022.
2022 Cost of Capital	Leave cost of capital components at pre-2022 levels for 2022	Filed August 2021. Briefing is expected to be completed by March 2022.
2015 GT&S	Revenue requirement of $416 million	Settlement agreement to recover $356 million of revenue requirement filed July 2021.

2023 General Rate Case

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC. The 2023 GRC combined what had historically been separated into the GRC and GT&S rate cases. In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC.

In a GRC, the CPUC approves annual revenue requirements for the first year (a “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). For its 2023 test year, the Utility has requested revenue requirements of $15.46 billion, an increase of $3.56 billion over the adopted 2020 GRC and 2019 GT&S revenue requirements for 2022 of $11.90 billion. The GRC application further states that the Utility’s requested 2023 revenue requirements represent a 9.6% increase over its total revenue requirements for 2022 (including both amounts that are authorized and that are requested outside of the GRC and remain subject to the regulatory process). The requested weighted-average GRC rate base for 2023 is approximately $48.52 billion, which corresponds to an increase of $9.35 billion over the authorized rate base for 2022 of $39.17 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized GRC revenues in 2024, 2025, and 2026 by $930 million, $590 million, and $381 million, respectively. The Utility estimated its proposed revenue requirements for 2024, 2025, and 2026 would result in revenue requirement increases of 2.4%, 1.9%, and 1.5%, compared to its total estimated revenue requirements for 2023, 2024, and 2025, respectively. Over the 2023-2026 GRC period, the Utility plans to make average annual capital investments of approximately $7.75 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

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The following table compares the Utility’s initial requested revenue requirements for 2023 with the comparable revenue requirements currently authorized for 2022, by both line of business and cost category:

Line of Business (1)	Amounts requested in the 2023 GRC application		Amounts currently authorized for 2022 (2)		Requested increase compared to currently authorized amounts
(in millions)
Gas distribution	$	2,870	$	2,321	$	550
Gas transmission and storage	1,989		1,662		327
Electric distribution	8,171		5,514		2,657
Electric generation	2,431		2,404		26
Total revenue requirements	$	15,461	$	11,901	$	3,560

(1) May not sum due to rounding.

(2) These amounts include revenues from Decision (“D.”) 20-12-005 (the Utility’s 2020 GRC), D.19-09-025 (the Utility’s 2019 GT&S) adjusted for D.19-12-056 and Advice Letter (“AL”) 4275-G/5887-E (Cost of Capital changes adopted for Long Term Debt and Common Stock) and AL 4367-G/6062-E (Excess Accumulated Deferred Income Taxes Pursuant to the 2017 Tax Act). Also included are the 2022 adopted revenue requirements associated with the following previously separately-funded projects: AL 5322-E (Energy Storage), D.16-12-065 (Electric Vehicle Charging Network Phase I), D.14-03-021 (Mobile Home Park to the Meter), D.20-11-035 (2019 CEMA), AL 4392-G/6100-E (WMBA and VMBA), AL 4444-G/6210-E (RTBA).

In the 2023 GRC application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Among other things, the Utility proposed to invest a total of approximately $31 billion between 2023 and 2026 to reduce wildfire risk; improve gas and electric system safety, reliability, and resiliency; increase the use of new, innovative technologies; and expand its clean energy infrastructure.

In addition to coverage that may be available from the private insurance market, the Utility also proposed to use self-insurance as part of its wildfire insurance program as follows: (1) the Utility’s recommended approach, a new self-insurance structure whereby the Utility would seek customer-funded self-insurance in the amount of $250 million annually and traditional private insurance procurement for amounts between the accumulated self-insurance balance and $1.0 billion; or, alternatively (2) continuing the currently authorized mechanism whereby the Utility seeks procurement of wildfire liability insurance instruments through the private insurance market and is authorized to use any unspent authorized revenue requirements on self-insurance.

In addition, the Utility requested authorization to establish one new balancing account and one new memorandum account as follows:

•Catastrophic Events Straight-Time Labor Balancing Account, a two-way account which would recover straight-time labor costs associated with catastrophic events. These costs are currently recovered through the Catastrophic Events Memorandum Account process.

•Helms Capacity Memorandum Account, which would allow the Utility to track and recover the actual costs associated with upgrading the Helms Pumped Storage Facility through a future application.

The Utility did not seek recovery of compensation of PG&E Corporation’s and the Utility’s officers within the scope of 17 Code of Federal Regulations 240.3b-7.

On October 1, 2021, the CPUC issued a scoping memo indicating that the CPUC will issue a decision on an initial track of the proceeding in the second quarter of 2023. The scoping memo also established a second track of the 2023 GRC to consider costs incurred from 2019 to 2021 that are recorded in balancing or memorandum accounts for, among other work, wildfire mitigation and gas system safety improvements. The second track will review more than $500 million in capital and $160 million in expense included in the Utility’s initial 2023 GRC application for the period from 2019 to 2020, plus additional costs recorded in memorandum and balancing accounts in 2021. The scoping memo indicated that the CPUC will issue a decision on the second track in the third quarter of 2023. The scoping memo also directed the Utility to file an update for its

undergrounding program in February 2022.

On November 5, 2021, the Utility filed a motion to revise the proceeding schedule.

Between August 2021 and January 2022, the Utility served updates to its 2023 GRC testimony that would, if approved, reduce the requested revenue requirement in 2023 by approximately $181 million in the aggregate.

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2020 General Rate Case

On December 3, 2020, the CPUC approved the final decision for the Utility’s 2020 GRC.

Revenue Requirements and Attrition Year Revenues

The final decision approved a 2020 authorized revenue requirement of $9.102 billion, effective January 1, 2020. The CPUC also approved the revenue requirements for 2021 and 2022 as follows: an additional increase of $316 million in 2021 over the authorized 2020 revenue requirement, or a 3.5% increase, and an additional increase of $364 million in 2022, or a 3.9% increase. The Utility is authorized to collect in rates the difference between the revenue requirement in effect and the 2020 GRC decision-authorized revenue requirement for the period of January 1, 2020 to February 28, 2021 over the period of March 1, 2021 through December 31, 2022.

The final decision also allows the Utility to recover the annual cost of excess liability insurance for coverage of up to $1.4 billion. An advice letter is required for recovery of excess liability insurance costs for coverage exceeding $1.4 billion. The final decision also approved wildfire mitigation capital expenditures in the Community Wildfire Safety Program of $603 million in 2020, $931 million in 2021 and $1.15 billion in 2022. In addition, the final decision requires a reasonableness review and recovery of WMBA costs or unit costs for system hardening in excess of 115% of the adopted amounts and VMBA costs in excess of 120% of the adopted amounts through an application.

Rate Base and Capital Additions

The CPUC also adopted a rate base of $31.0 billion in 2021, or a 5.4% increase over 2020; and $33.0 billion in 2022, or a 6.3% increase over 2021. Consistent with AB 1054, the decision provides for a total of $2.83 billion in forecast capital spend without an equity return for the period of August 2019 to December 2022, which includes $931 million for 2021 and $1.15 billion for 2022.

Over the 2020-2022 GRC period, the decision provided average annual capital investments of approximately $4.5 billion in electric distribution, natural gas distribution and electric generation infrastructure.

2019 Gas Transmission and Storage Rate Case

As previously disclosed, on September 12, 2019, the CPUC approved the final decision in the 2019 GT&S rate case of the Utility. The CPUC adopted revenue requirements of $1.516 billion for 2021 and $1.580 billion for 2022, compared to the Utility’s request of $1.693 billion for 2021 and $1.679 billion for 2022.

On October 23, 2019, the Utility filed an application with the CPUC requesting the rehearing of the final decision. Specifically, issues identified by the Utility include the adopted disallowance associated with vintage pipe replacement, reduction in the Utility’s expense forecast for in-line inspections, and establishment of a memo account for Internal Corrosion Direct Assessment. On November 19, 2021, the CPUC issued a decision denying the Utility’s application for rehearing but allowing the Utility to file an advice letter to remove the 2015 portion of the capital vintage pipe replacement disallowance. The advice letter was approved by the CPUC on January 21, 2022.

Removing the 2015 value of $39.4 million from the disallowance reduced the total disallowed amount from $237.3 million to $197.9 million.

Cost of Capital Proceedings

On December 19, 2019, the CPUC approved a final decision in the 2020 cost of capital application (the “2020 cost of capital application”), maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020. The decision maintained the common equity component of the Utility’s capital structure at 52% and reduced its preferred stock component from 1% to 0.5%. The decision also approved the cost of debt requested by the Utility.

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The Utility’s annual cost of capital adjustment mechanism, which allows for changes in the Utility’s authorized ROE and cost of debt, also remained unchanged by the final 2020 cost of capital application decision. The mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the index)) and (ii) 4.5% (the benchmark) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general, and the Utility in particular, to the same extent as the overall financial markets (the “2022 cost of capital application”). The 2022 cost of capital application requested that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure. The Utility also concurrently filed a motion requesting that the revenue requirement for the 2022 cost of capital be recorded in memorandum accounts to be trued-up following a final decision in this proceeding.

In September 2021, the cost of capital adjustment mechanism was triggered because the index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.

On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes starting on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application.

On December 24, 2021, the CPUC issued a scoping memo in the 2022 cost of capital application limiting the scope of the Utility’s 2022 cost of capital application to the 2022 cost of capital only. The scoping memo also affirmed that the Utility is to file a 2023 cost of capital application in April 2022 for the 2023 test year.

To set the 2022 cost of capital, the CPUC will consider (i) whether there are extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022; and (ii) if so, whether to leave the cost of capital components at pre-2022 levels for the year 2022, or open a second phase to consider alternative cost of capital proposals for the year 2022. The Utility’s position is that there are extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022 and that the CPUC should leave the cost of capital components at pre-2022 levels for 2022.

If the CPUC determines that the 2022 cost of capital application establishes extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022 and leaves the Utility’s cost of capital components at pre-2022 levels for 2022, the cost of long-term debt would be 4.17%, the return on preferred stock would be 5.52%, and the ROE would be 10.25%. If the CPUC opens a second phase of the proceeding, the CPUC would set the cost of capital for 2022 based on alternative cost of capital proposals that would address the technical cost of capital material included within the Utility’s 2022 cost of capital application.

If the CPUC determines that there are not extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022, the cost of capital adjustment mechanism would operate and the cost of long-term debt would be 4.15%, the return on preferred stock would be 5.52%, and the ROE would be 9.67%. The resulting decrease in the CPUC jurisdictional gas and electric revenue requirement would be approximately $163 million ($99 million electric and $64 million gas).

The scoping memo called for briefing to be completed by March 25, 2022 but did not indicate timing for a PD or final decision.

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2015 Gas Transmission and Storage Rate Case

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 2011 to 2014 capital spending in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. For more information regarding this proceeding, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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 the 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 the 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 the FERC for further proceedings consistent with the Ninth Circuit Court of Appeals’ opinion.

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder.

On March 17, 2020, the FERC issued its order denying requests for rehearing that were previously filed by several parties. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals. Oral argument was held on April 16, 2021.

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

As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case with 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 ROE of 10.9%, which included an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. 

On October 15, 2020, the FERC issued an order that, among other things, 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. The order reopened the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020. Initial briefs and testimony were filed on December 14, 2020 and responses were filed on February 12, 2021.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (1) impact of the Tax Act on TO18 rates in January and February 2018 and (2) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are currently being held in abeyance until the FERC addresses the ROE issue.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2021 by approximately $324 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, as of December 31, 2021, the Utility has recorded approximately $197 million to Regulatory assets.

Aside from the ultimate outcome of the common plant allocation, which is subject to further appellate briefing and a further FERC decision on ROE, that 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 TO19 and TO20 rate cases. See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility. 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 Ninth Circuit 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.

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

As previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case with the 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. The FERC also ordered that the hearings be held in abeyance pending settlement discussions among the parties.

On March 31, 2020, the Utility filed a partial settlement with the FERC, which the FERC approved on August 17, 2020. On October 15, 2020, the Utility filed a settlement with the 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 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.

On December 30, 2020, the FERC approved the settlement without modifications.

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 TO19 and TO20 rate cases.

Other Regulatory Proceedings

Application to Sell General Office Complex

On September 30, 2020, the Utility filed an application with the CPUC to sell the SFGO located at 25 Beale Street, 45 Beale Street, 77 Beale Street, 50 Main Street, 215 Market Street and 245 Market Street in downtown San Francisco, and to recover costs to relocate its staff at the SFGO to a new headquarters at the Lakeside Building, and for appropriate ratemaking treatment of those transactions.

On May 21, 2021, the Utility entered into a purchase agreement with HNG Atlas US LP, to sell the SFGO for $800 million.

On May 26, 2021, the Utility filed an amended settlement agreement with the CPUC. Under the amended settlement, the parties agreed that (1) the Utility’s headquarters strategy, including the move to the Lakeside Building, the sale of the SFGO, and the terms of the agreement to lease and the option to purchase the Lakeside Building, is reasonable, (2) all of the net gain on sale of the SFGO will be distributed to customers over five years, beginning in 2022, and (3) the costs associated with the Utility’s move to the Lakeside Building and development will be considered at later stages of the proceeding through a petition for modification of the final decision in the proceeding.

The CPUC issued a final decision approving the purchase agreement and the ratemaking treatment proposed under the parties’ settlement on August 19, 2021, and the sale closed on September 17, 2021. The final decision defers, until the petition for modification, determinations as to the amount of the Utility’s cost recovery in connection with the anticipated purchase of the Lakeside Building and operating and capital expenses related to the transition to the Lakeside Building.

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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 recover $7.5 billion of 2017 wildfire claims costs through securitization 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. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested 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 proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds.

On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. and approving a structure for the transaction. As requested, the decision authorizes the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders, that will provide a monthly credit to customers that is anticipated to equal the securitized charges such that the securitization is designed to be rate neutral to customers. Subject to retention of the CPUC’s existing jurisdiction, the decision adopts a transaction structure comprised of four elements (1) an initial shareholder contribution of $2.0 billion, with $1.0 billion to be contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. Three parties filed applications for rehearing of the decision on May 3, 2021, and the Utility filed a response to those applications on May 14, 2021. On August 12, 2021, the CPUC issued a decision denying the applications for rehearing.

Separately, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On May 11, 2021, the CPUC issued a decision granting the Utility’s January 2021 application for a financing order authorizing the issuance of $7.5 billion of recovery bonds in connection with the rate neutral securitization proceeding. Two parties filed applications for rehearing of the financing order, and the Utility filed a response to those applications for rehearing on June 4, 2021. On August 12, 2021, the CPUC issued a decision denying the applications for rehearing.

On September 10, 2021, TURN filed a petition for writ of review of the decision and financing order in state court. Responses to the petition were filed on October 15, 2021. TURN filed a reply in support of the petition on November 9, 2021.

Application for AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs 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 has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.) AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge.

On February 24, 2021 the Utility filed an application with the CPUC seeking authorization for a transaction to finance, using securitization, up to $1.19 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility in 2020 and 2021, with the final amount to be financed based on recorded 2020 and 2021 Community Wildfire Safety Program capital expenditures incurred by the Utility prior to the securitization transaction.

The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest and would reduce rates on a present value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.  The application also requested to exclude the securitized debt from the Utility’s ratemaking capital structure and to adjust its 2020 GRC revenue requirement following the issuance of the recovery bonds. 

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On June 24, 2021, the CPUC issued a decision granting the Utility’s application and authorizing the Utility to issue up to approximately $1.2 billion of recovery bonds. On July 6, 2021, the financing order became final and non-appealable. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048.    

2020-2022 Wildfire Mitigation Plan

As previously disclosed, on February 7, 2020, the Utility submitted its 2020 WMP and the related 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 PSPS events, as well as providing historical data. The Utility’s 2020 WMP covers a three-year period from 2020 to 2022 but is updated annually.

The Utility’s 2021 WMP was submitted on February 5, 2021. The 2021 WMP updated the 2020 WMP and addressed the Utility’s wildfire safety programs focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread and reducing the impact of PSPS events.

On September 22, 2021, OEIS issued a final action statement approving the Utility’s 2021 WMP and on October 21, 2021, the CPUC ratified OEIS’s approval.

In 2021, the Utility notified the CPUC that it had missed inspections and other targets subject to the 2020 WMP. The Utility is undertaking a review of its electric asset inspections. For more information, see “Electric Asset Inspections” below.

On December 16, 2021, the CPUC closed the WMP proceeding, noting that OEIS is now responsible for review and approval of the WMP.

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 IOUs prioritized safety and complied with the CPUC’s regulations and requirements with respect to their PSPS events in late 2019.”

On June 7, 2021, the CPUC issued a final decision in the case that found each of the large electric IOUs to be noncompliant with CPUC-required guidelines in certain of their 2019 PSPS events. The decision included a financial remedy and a number of corrective actions. The financial remedy consists of forgoing collection of revenues from customers associated with electricity not sold during future PSPS events until it can be demonstrated that the utilities have made improvements in assessing public harm when determining whether to initiate a PSPS event. The corrective actions involve the Utility’s processes, reporting, and other aspects of its PSPS program. On July 7, 2021, the Acton Town Council filed an application to rehear the decision. Responses to the application for rehearing were filed on July 22, 2021.

Integrated Resource Planning Procurement

On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision requires incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period 2021-2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision requires that at least 50% of LSE resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directs the IOUs to act as the backstop procurement agent for CCAs and energy service providers that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision.

The Utility procured its required RA capacity for the August 1, 2021 milestone from third parties through CPUC-approved contracts for lithium-ion battery energy storage resources with terms ranging from 10-15 years. On December 22, 2020, the Utility filed an advice letter seeking CPUC approval of an additional group of similar contracts that would satisfy the balance of the Utility’s procurement obligations for the August 1, 2022 and August 1, 2023 milestones. On April 15, 2021, the CPUC approved the contracts.

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On June 24, 2021, the CPUC adopted a mid-term reliability decision to address incremental electric system reliability needs between 2024 and 2026 due to, in part, the pending retirements of Diablo Canyon and once-through-cooling natural gas plants in Southern California by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs subject to the CPUC’s integrated resource planning authority. The decision sets procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision sets the Utility’s share of the procurement at 2,302 MW of incremental net qualifying capacity.

On January 21, 2022, the Utility filed an advice letter with the CPUC seeking approval of a group of nine long-term RA agreements to meet a portion of its procurement requirements under the CPUC’s mid-term reliability decision. The agreements are each for a term of 15 years and collectively supply 1,598.7 MW of lithium-ion energy storage capacity with some projects expected to be operational in 2023 and others in 2024.

OIR to Further Develop a Risk-Based Decision-Making Framework for Electric and Gas Utilities

On July 20, 2020, the CPUC initiated a rulemaking proceeding to consider ways to strengthen the risk-based decision-making framework that energy utilities use to assess, manage, mitigate and minimize safety risks.

On November 4, 2021, the CPUC issued a final decision adopting 32 safety and operational metrics, which can serve as triggering events in the EOEP and requiring the Utility to report on performance against these metrics on a semi-annual basis. The Utility is required to submit the first report by March 31, 2022. The Utility will propose one- and five-year targets for each metric in such report.

OIR to Revisit Net Energy Metering Tariffs

On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers.

On December 13, 2021, the CPUC issued a PD that would reduce the compensation for new non-CARE NEM customers by about 80 percent for standalone solar and about 60 percent for solar-paired storage. Commercial customer NEM compensation would be reduced by about 35 percent. Additionally, the PD would reduce the legacy period for existing non-CARE NEM customers from 20 years to 15 years after which such customers would transition to the successor tariff. Comments and reply comments on the PD were filed in January 2022. The PD has not yet been scheduled to be voted on by the CPUC.

OIR to Address Energy Utility Customer Debt Accumulated during the COVID-19 Pandemic

On February 11, 2021, the CPUC initiated a rulemaking proceeding to consider arrearage relief for utility customers with outstanding utility bills when the moratorium on service disconnections ended. The OIR will evaluate a more global program beyond the currently approved arrearage management program focused on low-income residential customers that is funded by the Utility’s customers. The OIR may consider various funding approaches for this expanded debt forgiveness proposal, which could include shareholder funding.

On June 30, 2021, the CPUC issued a final decision directing the Utility and other IOUs to automatically enroll residential customers and small business customers more than 60 days in arrears in payment plans. The decision also extended the moratorium on service disconnections for residential and small business, as well as medium and large commercial and industrial customers, through September 30, 2021.

On November 19, 2021, the CPUC issued a decision authorizing IOUs to allocate payments made on past-due electric utility bills proportionally between utilities and CCAs through September 2024.

Self-Reports to the CPUC

The Utility self-reports certain errors and omissions to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these errors or omissions, including under the EOEP. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

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Electric Asset Inspections

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 (including failure to perform inspections in compliance with GO 165 of approximately 55,000 poles in 2020) and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence in the future. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

The Utility continues to evaluate whether there are additional failures to comply with GOs 95 and 165 and the 2020 WMP, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews.

On November 21, 2021, the SED issued two citations to the Utility in relation to the Utility’s self-reports. One citation was for incomplete inspections performed on distribution poles as required under GO 165, and the other citation was for the Utility’s failure to adequately inspect a transmission line. The citations resulted in penalties of $2.5 million and $5 million, respectively, which the Utility paid in full on December 22, 2021.

Subsurface Electric Ducts

On October 21, 2021, the Utility notified the CPUC of inconsistent application of the requirements to locate and mark empty subsurface electric ducts in accordance with Government Code section 4216(k), 4216(s) and 4216.3(a)(1)(A).

LEGISLATIVE AND REGULATORY INITIATIVES

Assembly Bill 242

Assembly Bill 242, which was signed into law on September 23, 2021, expanded the definition of a “covered wildfire” from AB 1054 to also include those wildfires determined by a court of competent jurisdiction to be caused by an electrical corporation, and those wildfires asserted to have been caused by an electrical corporation that result in a court-approved dismissal resulting from the settlement of third-party damage claims.

Assembly Bill 135

On July 16, 2021, the California governor approved AB 135, which established the CAPP. CAPP enables the IOUs to apply for a statewide total of approximately $695 million to offset customer arrearages incurred during the COVID-19 pandemic. The Utility received approximately $300 million in January 2022 to reduce the amounts owed by customer accounts in arrears. The amount of funding was determined by the California Department of Community Services and Development, which is the agency responsible for administering the CAPP.

Vaccine Mandates

On September 9, 2021, President Biden issued an EO that would require certain COVID-19 precautions for government contractors and their subcontractors, including mandatory employee vaccination. The requirements under the EO is currently stayed pending the outcome of ongoing litigation. The ultimate implementation of the EO could result in workplace disruptions, employee attrition, and difficulty securing future labor needs.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel.  See Item 1A. Risk Factors, “Environmental Regulation” in Item 1. and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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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 non-trading purposes (i.e., risk mitigation) and not for speculative purposes.

Commodity Price Risk

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. 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. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices do not affect earnings. Such fluctuations, however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility’s current authorized revenue requirement for natural gas transportation and storage service to non-core customers is not balancing account protected. The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $5 million and $14 million at December 31, 2021 and 2020, respectively. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. for further discussion of price risk management activities.

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2021 and 2020, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $76 million and $89 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. for further discussion of interest rates.

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas and related services, then the Utility may find it necessary to procure electricity or gas at current market prices or seek alternate services, which may be higher than the contract prices.

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. The Utility executes many energy contracts under master commodity enabling agreements that may require security. Security may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Security or performance assurance may be required from the Utility or counterparties when current net receivables/payables and exposure exceed contractually specified limits.

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The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties:

	Exposure (1) (in millions)		Number of Wholesale Customers or Counterparties >10%	Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions)
December 31, 2021	$	570	1	$	63
December 31, 2020	$	250	2	$	57

(1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the 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 financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting estimates 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 estimates and their key characteristics are outlined below.

Contributions to the Wildfire Fund

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 customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as HFTDs 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).

On the Emergence 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. The other large electric IOUs made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020 and 2021, the Utility made its second and third annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility have seven remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). 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.

As of December 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.1 billion in Other non-current liabilities, $461 million in current assets - Wildfire fund asset, and $5.3 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2021 and 2020, the Utility recorded amortization and accretion expense of $517 million and $413 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. 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.

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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 that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. 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 creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a five-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 have decreased the amortization period to six years. As of December 31, 2021, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by three years assuming greater effectiveness and would decrease the amortization period by two 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 and determination of any amounts required to be reimbursed to the Wildfire Fund, 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 and 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 assess the Wildfire Fund asset for acceleration of the amortization of the asset 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 acceleration of the amortization of the asset 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. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire and $43 million of accelerated amortization, reflected in Wildfire Fund expense.

For more information, see “Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 3 and “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Loss Contingencies

As discussed below, PG&E Corporation and the Utility have recorded material accruals for various wildfire-related, enforcement and legal matters, and environmental remediation liabilities. PG&E Corporation and the Utility have also recorded insurance receivables for third-party claims.

Wildfire-Related Liabilities

PG&E Corporation and the Utility are subject to potential liabilities related to wildfires.  PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

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Potential liabilities related to wildfires depend on various factors, including negotiations and settlements or the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. 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 or the Utility. For example, the Utility’s wildfire-related accruals have changed in the past as new facts and information became available to the Utility, including the availability of new evidence and additional information about the scope and nature of damages.

The process for estimating wildfire-related liabilities 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.  See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Enforcement and Litigation Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss contingency 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, 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. Actual results may differ materially from these estimates and assumptions. See Note 14 and “Enforcement and Litigation Matters” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur and they can reasonably estimate the amount or its range.  The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events.  Loss recoveries are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former MGP sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

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The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has a program related to certain former MGP sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort.

As of December 31, 2021 and 2020, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each. The Utility’s undiscounted future costs could increase to as much as $2.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.

Regulatory Accounting

As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. Despite the ongoing losses related to wildfires (see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.), there is no actual or anticipated change in the cost of service regulation of the Utility’s operations. Therefore, the Utility continues to apply the accounting ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and Regulated Operations” in Note 3 as well as Note 4 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2021, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $12.7 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $13.8 billion.

Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility’s regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition.

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A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA and RUBA accounts 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. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. For more information, see “Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account” and “Regulatory Matters - Catastrophic Event Memorandum Accounts and Applications” above.

Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, 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. The Utility must evaluate the likelihood of recovery in future rates each period. If the criteria are met at a later date, the Utility would recognize a regulatory asset and a related gain in the consolidated income statement in the period in which it is determined that the likelihood of recovery is probable.

In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered.  The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. 

Asset Retirement Obligations

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. See Notes 3 and 4 of the Notes to the Consolidated Financial Statements in Item 8.

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation.

At December 31, 2021, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.3 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.

Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. Adjustments to the pension and other benefit obligation are based on the differences between actuarial assumptions and actual plan results. These amounts are deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery through rates. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

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The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.

In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2022 was 6.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond.

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the Utility’s defined benefit pension plan, the assumed return of 5.5% compares to a ten-year actual return of 9.6%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 817 Aa-grade non-callable bonds at December 31, 2021. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:

(in millions)	Increase (Decrease) in Assumption		Increase in 2021 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2021
Discount rate	(0.50)	%	$	111	$	1,872
Rate of return on plan assets	(0.50)	%	103		—
Rate of increase in compensation	0.50	%	51		403

The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:

(in millions)	Increase (Decrease) in Assumption		Increase in 2021 Other Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2021
Health care cost trend rate	0.50	%	$	9	$	58
Discount rate	(0.50)	%	12		138
Rate of return on plan assets	(0.50)	%	15		—

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year ended December 31,
	2021		2020		2019
Operating Revenues
Electric	$	15,131	$	13,858	$	12,740
Natural gas	5,511		4,611		4,389
Total operating revenues	20,642		18,469		17,129
Operating Expenses
Cost of electricity	3,232		3,116		3,095
Cost of natural gas	1,149		782		734
Operating and maintenance	10,200		8,684		8,725
Wildfire-related claims, net of recoveries	258		251		11,435
Wildfire fund expense	517		413		—
Depreciation, amortization, and decommissioning	3,403		3,468		3,234
Total operating expenses	18,759		16,714		27,223
Operating Income (Loss)	1,883		1,755		(10,094)
Interest income	20		39		82
Interest expense	(1,601)		(1,260)		(934)
Other income, net	457		483		250
Reorganization items, net	(11)		(1,959)		(346)
Income (Loss) Before Income Taxes	748		(942)		(11,042)
Income tax provision (benefit)	836		362		(3,400)
Net Loss	(88)		(1,304)		(7,642)
Preferred stock dividend requirement of subsidiary	14		14		14
Loss Attributable to Common Shareholders	$	(102)	$	(1,318)	$	(7,656)
Weighted Average Common Shares Outstanding, Basic	1,985		1,257		528
Weighted Average Common Shares Outstanding, Diluted	1,985		1,257		528
Net Loss Per Common Share, Basic	$	(0.05)	$	(1.05)	$	(14.50)
Net Loss Per Common Share, Diluted	$	(0.05)	$	(1.05)	$	(14.50)

See accompanying Notes to the Consolidated Financial Statements.

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PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2021		2020		2019
Net Loss	$	(88)	$	(1,304)	$	(7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $7, and $0, at respective dates)	7		(17)		(1)
Total other comprehensive income (loss)	7		(17)		(1)
Comprehensive Loss	(81)		(1,321)		(7,643)
Preferred stock dividend requirement of subsidiary	14		14		14
Comprehensive Loss Attributable to Common Shareholders	$	(95)	$	(1,335)	$	(7,657)

See accompanying Notes to the Consolidated Financial Statements.

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PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2021		2020
ASSETS
Current Assets
Cash and cash equivalents	$	291	$	484
Restricted Cash	16		143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345		1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207		1,083
Regulatory balancing accounts	2,999		2,001
Other	1,784		1,172
Regulatory assets	496		410
Inventories
Gas stored underground and fuel oil	44		95
Materials and supplies	552		533
Wildfire fund asset	461		464
Other	882		1,334
Total current assets	11,077		9,602
Property, Plant, and Equipment
Electric	69,482		66,982
Gas	25,979		24,135
Construction work in progress	3,479		2,757
Financing lease and other	20		20
Total property, plant, and equipment	98,960		93,894
Accumulated depreciation	(29,134)		(27,758)
Net property, plant, and equipment	69,826		66,136
Other Noncurrent Assets
Regulatory assets	9,207		8,978
Nuclear decommissioning trusts	3,798		3,538
Operating lease right of use asset	1,234		1,741
Wildfire fund asset	5,313		5,816
Income taxes receivable	9		67
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,863		1,978
Total other noncurrent assets	22,424		22,118
TOTAL ASSETS	$	103,327	$	97,856

See accompanying Notes to the Consolidated Financial Statements.

102

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2021		2020
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,184	$	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481		28
Accounts payable
Trade creditors	2,855		2,402
Regulatory balancing accounts	1,121		1,245
Other	679		580
Operating lease liabilities	468		533
Disputed claims and customer refunds	—		242
Interest payable	481		498
Wildfire-related claims	2,722		2,250
Other	2,436		2,256
Total current liabilities	17,427		13,581
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	38,225		37,288
Regulatory liabilities	11,999		10,424
Pension and other postretirement benefits	860		2,444
Asset retirement obligations	5,298		6,412
Deferred income taxes	3,177		1,398
Operating lease liabilities	810		1,208
Other	4,308		3,848
Total noncurrent liabilities	64,677		63,022
Contingencies and Commitments (Notes 14 and 15)
Equity
Shareholders' Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,985,400,540 and 1,984,678,673 shares outstanding at respective dates	35,129		30,224
Treasury Stock, at cost; 477,743,590 and 0 shares at respective dates	(4,854)		—
Reinvested earnings	(9,284)		(9,196)
Accumulated other comprehensive loss	(20)		(27)
Total shareholders' equity	20,971		21,001
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	21,223		21,253
TOTAL LIABILITIES AND EQUITY	$	103,327	$	97,856

See accompanying Notes to the Consolidated Financial Statements.

103

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities
Net income (loss)	$	(88)	$	(1,304)	$	(7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403		3,468		3,234
Bad Debt Expense	154		150		46
Allowance for equity funds used during construction	(133)		(140)		(79)
Deferred income taxes and tax credits, net	1,783		1,097		(2,948)
Reorganization items, net (Note 2)	(73)		1,458		108
Wildfire fund expense	517		413		—
Disallowed capital expenditures	—		17		581
Other	248		249		161
Effect of changes in operating assets and liabilities:
Accounts receivable	(589)		(1,182)		(104)
Wildfire-related insurance receivable	(723)		1,564		35
Inventories	(32)		6		(80)
Accounts payable	117		58		516
Wildfire-related claims	472		(16,525)		(114)
Income taxes receivable/payable	—		—		23
Other current assets and liabilities	244		(1,079)		77
Regulatory assets, liabilities, and balancing accounts, net	(2,266)		(2,451)		(1,417)
Liabilities subject to compromise	—		413		12,222
Contributions to Wildfire fund	(193)		(5,200)		—
Other noncurrent assets and liabilities	(579)		(142)		197
Net cash provided by (used in) operating activities	2,262		(19,130)		4,816
Cash Flows from Investing Activities
Capital expenditures	(7,689)		(7,690)		(6,313)
Proceeds from sale of the SFGO	749		—		—
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678		1,518		956
Purchases of nuclear decommissioning trust investments	(1,702)		(1,590)		(1,032)
Other	59		14		11
Net cash used in investing activities	(6,905)		(7,748)		(6,378)
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	—		(6)		(113)
Bridge facility financing fees	—		(73)		—
Borrowings under credit facilities	9,730		8,554		—
Repayments under credit facilities	(9,976)		(3,949)		—
Credit facilities financing fees	(9)		(22)		—
Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300		1,448		—

104

Short-term debt matured	(1,450)		—		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance     costs of $43, $178, and $0 at respective dates	5,474		13,497		—
Repayment of long-term debt	(87)		(764)		—
Proceeds from sale of future revenue from transmission tower license sales, net of fees	370		—		—
Exchanged debt financing fees	—		(103)		—
Common stock issued	—		7,582		85
Equity Units issued	—		1,304		—
Other	(29)		(40)		(8)
Net cash provided by financing activities	4,323		25,928		1,464
Net change in cash, cash equivalents, and restricted cash	(320)		(950)		(98)
Cash, cash equivalents, and restricted cash at January 1	627		1,577		1,675
Cash, cash equivalents, and restricted cash at December 31	$	307	$	627	$	1,577
Less: Restricted cash and restricted cash equivalents	(16)		(143)		(7)
Cash and cash equivalents at December 31	$	291	$	484	$	1,570

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,404)	$	(1,563)	$	(10)
Income taxes, net	99		—		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,311	$	515	$	826
Operating lease liabilities arising from obtaining ROU assets	100		13		2,816
Common stock issued in satisfaction of liabilities	—		8,276		—
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement	4,854		—		—

See accompanying Notes to the Consolidated Financial Statements.

105

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

	Common Stock			Treasury Stock			Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity		Non- controlling Interest - Preferred Stock  of Subsidiary		Total Equity
	Shares	Amount		Shares	Amount
Balance at December 31, 2018	520,338,710	$	12,910	—	$	—	$	(250)	$	(9)	$	12,651	$	252	$	12,903
Net loss	—	—		—	—		(7,642)		—		(7,642)		—		(7,642)
Other Comprehensive loss	—	—		—	—		—		(1)		(1)		—		(1)
Common stock issued, net	8,898,031	85		—	—		—		—		85		—		85
Stock-based compensation amortization	—	43		—	—		—		—		43		—		43
Balance at December 31, 2019	529,236,741	$	13,038	—	$	—	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388
Net loss	—	—		—	—		(1,304)		—		(1,304)		—		(1,304)
Other comprehensive loss	—	—		—	—		—		(17)		(17)		—		(17)
Common stock issued, net	1,455,441,932	15,854		—	—		—		—		15,854		—		15,854
Equity units issued	—	1,304		—	—		—		—		1,304		—		1,304
Stock-based compensation amortization	—	28		—	—		—		—		28		—		28
Balance at December 31, 2020	1,984,678,673	$	30,224	—	$	—	$	(9,196)	$	(27)	$	21,001	$	252	$	21,253
Net loss	—	—		—	—		(88)		—		(88)		—		(88)
Other comprehensive income	—	—		—	—		—		7		7		—		7
Common stock issued, net (1)	721,867	4,854		—	—		—		—		4,854		—		4,854
Treasury stock acquired	—	—		477,743,590	(4,854)		—		—		(4,854)		—		(4,854)
Stock-based compensation amortization	—	51		—	—		—		—		51		—		51
Balance at December 31, 2021	1,985,400,540	$	35,129	477,743,590	$	(4,854)	$	(9,284)	$	(20)	$	20,971	$	252	$	21,223

(1) Excludes 477,743,590 shares of common stock issued to ShareCo. For more information, see Note 6 below.

See accompanying Notes to the Consolidated Financial Statements.

106

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

	Year ended December 31,
	2021		2020		2019
Operating Revenues
Electric	$	15,131	$	13,858	$	12,740
Natural gas	5,511		4,611		4,389
Total operating revenues	20,642		18,469		17,129
Operating Expenses
Cost of electricity	3,232		3,116		3,095
Cost of natural gas	1,149		782		734
Operating and maintenance	10,194		8,707		8,750
Wildfire-related claims, net of recoveries	258		251		11,435
Wildfire fund expense	517		413		—
Depreciation, amortization, and decommissioning	3,403		3,469		3,233
Total operating expenses	18,753		16,738		27,247
Operating Income (Loss)	1,889		1,731		(10,118)
Interest income	22		39		82
Interest expense	(1,373)		(1,111)		(912)
Other income, net	512		470		239
Reorganization items, net	(12)		(310)		(320)
Income (Loss) Before Income Taxes	1,038		819		(11,029)
Income tax provision (benefit)	900		408		(3,407)
Net Income (Loss)	138		411		(7,622)
Preferred stock dividend requirement	14		14		14
Income (Loss) Available for Common Stock	$	124	$	397	$	(7,636)

See accompanying Notes to the Consolidated Financial Statements.

107

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

	Year ended December 31,
	2021		2020		2019
Net Income (Loss)	$	138	$	411	$	(7,622)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes     of $1, $2, and $1, at respective dates)	(4)		(6)		2
Total other comprehensive income (loss)	(4)		(6)		2
Comprehensive Income (Loss)	$	134	$	405	$	(7,620)

See accompanying Notes to the Consolidated Financial Statements.

108

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)

	Balance at December 31,
	2021		2020
ASSETS
Current Assets
Cash and cash equivalents	$	165	$	261
Restricted Cash	16		143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345		1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207		1,083
Regulatory balancing accounts	2,999		2,001
Other	1,932		1,180
Regulatory assets	496		410
Inventories
Gas stored underground and fuel oil	44		95
Materials and supplies	552		533
Wildfire fund asset	461		464
Other	869		1,321
Total current assets	11,086		9,374
Property, Plant, and Equipment
Electric	69,482		66,982
Gas	25,979		24,135
Construction work in progress	3,480		2,757
Financing lease	18		18
Total property, plant, and equipment	98,959		93,892
Accumulated depreciation	(29,131)		(27,756)
Net property, plant, and equipment	69,828		66,136
Other Noncurrent Assets
Regulatory assets	9,207		8,978
Nuclear decommissioning trusts	3,798		3,538
Operating lease right of use asset	1,232		1,736
Wildfire fund asset	5,313		5,816
Income taxes receivable	7		66
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,706		1,818
Total other noncurrent assets	22,263		21,952
TOTAL ASSETS	$	103,177	$	97,462

See accompanying Notes to the Consolidated Financial Statements.

109

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	Balance at December 31,
	2021		2020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	2,184	$	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,455		—
Accounts payable
Trade creditors	2,853		2,366
Regulatory balancing accounts	1,121		1,245
Other	648		624
Operating lease liabilities	467		530
Disputed claims and customer refunds	—		242
Interest payable	430		444
Wildfire-related claims	2,722		2,250
Other	2,430		2,248
Total current liabilities	17,310		13,496
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	33,632		32,664
Regulatory liabilities	11,999		10,424
Pension and other postretirement benefits	764		2,328
Asset retirement obligations	5,298		6,412
Deferred income taxes	3,409		1,570
Operating lease liabilities	810		1,206
Other	4,345		3,886
Total noncurrent liabilities	60,257		58,490
Contingencies and Commitments (Notes 14 and 15)
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		28,286
Reinvested earnings	(4,247)		(4,385)
Accumulated other comprehensive loss	(9)		(5)
Total shareholders' equity	25,610		25,476
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	103,177	$	97,462

See accompanying Notes to the Consolidated Financial Statements.

110

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities
Net income (loss)	$	138	$	411	$	(7,622)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403		3,469		3,233
Bad Debt Expense	154		150		46
Allowance for equity funds used during construction	(133)		(140)		(79)
Deferred income taxes and tax credits, net	1,846		1,141		(2,952)
Reorganization items, net (Note 2)	(41)		(90)		97
Wildfire fund expense	517		413		—
Disallowed capital expenditures	—		17		581
Other	172		220		121
Effect of changes in operating assets and liabilities:
Accounts receivable	(584)		(1,160)		(132)
Wildfire-related insurance receivable	(723)		1,564		35
Inventories	(32)		6		(80)
Accounts payable	44		(24)		579
Wildfire-related claims	472		(16,525)		(114)
Income taxes receivable/payable	—		—		5
Other current assets and liabilities	251		(1,141)		101
Regulatory assets, liabilities, and balancing accounts, net	(2,266)		(2,451)		(1,417)
Liabilities subject to compromise	—		401		12,194
Contributions to Wildfire fund	(193)		(5,200)		—
Other noncurrent assets and liabilities	(577)		(108)		214
Net cash provided by (used in) operating activities	2,448		(19,047)		4,810
Cash Flows from Investing Activities
Capital expenditures	(7,689)		(7,690)		(6,313)
Proceeds from sale of the SFGO	749		—		—
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678		1,518		956
Purchases of nuclear decommissioning trust investments	(1,702)		(1,590)		(1,032)
Intercompany note to PG&E Corporation	(145)		—		—
Other	59		14		11
Net cash used in investing activities	(7,050)		(7,748)		(6,378)
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	—		(6)		(97)
Bridge facility financing fees	—		(33)		—
Borrowings under credit facilities	9,730		8,554		—
Repayments under credit facilities	(9,976)		(3,949)		—
Credit facilities financing fees	(9)		(22)		—

111

Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300		1,448		—
Short-term debt matured	(1,450)		—		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance     costs of $43, $88, and $0 at respective dates	5,474		8,837		—
Repayment of long-term debt	(59)		(100)		—
Proceeds from sale of future revenue from transmission tower license sales, net of fees	370		—		—
Exchanged debt financing fees	—		(103)		—
Equity contribution from PG&E Corporation	—		12,986		—
Other	(1)		(42)		(8)
Net cash provided by financing activities	4,379		26,070		1,395
Net change in cash, cash equivalents, and restricted cash	(223)		(725)		(173)
Cash, cash equivalents, and restricted cash at January 1	404		1,129		1,302
Cash, cash equivalents, and restricted cash at December 31	$	181	$	404	$	1,129
Less: Restricted cash and restricted cash equivalents	(16)		(143)		(7)
Cash and cash equivalents at December 31	$	165	$	261	$	1,122

 

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,198)	$	(1,458)	$	(7)
Income taxes, net	99		—		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,311	$	515	$	826
Operating lease liabilities arising from obtaining ROU assets	100		13		2,807
Common stock equity infusion from PG&E Corporation used to satisfy liabilities	—		6,750		—

 See accompanying Notes to the Consolidated Financial Statements.

112

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

	Preferred Stock		Common Stock		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 loss	—		—		—		(7,622)		—		(7,622)
Other comprehensive income	—		—		—		—		2		2
Balance at December 31, 2019	$	258	$	1,322	$	8,550	$	(4,796)	$	1	$	5,335
Net income	—		—		—		411		—		411
Other comprehensive loss	—		—		—		—		(6)		(6)
Equity Contribution	—		—		19,736		—		—		19,736
Balance at December 31, 2020	$	258	$	1,322	$	28,286	$	(4,385)	$	(5)	$	25,476
Net income	—		—		—		138		—		138
Other comprehensive loss	—		—		—		—		(4)		(4)
Balance at December 31, 2021	$	258	$	1,322	$	28,286	$	(4,247)	$	(9)	$	25,610

See accompanying Notes to the Consolidated Financial Statements.

113

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 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 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 Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of 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, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the 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.

NOTE 2: BANKRUPTCY FILING

Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence 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.

On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020.

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

Unresolved Chapter 11 Claims

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 a trust for the benefit of holders of certain subrogation claims (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 asserted litigation claims, trade creditor 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. Amounts expected to be allowed are reflected as current liabilities in the Consolidated Balance Sheets.

114

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 Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).

In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 14 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 14 under the heading “Securities Class Action Litigation.”

In addition to filing objections in the Bankruptcy Court to claims with respect to which PG&E Corporation and the Utility do not believe they have liability, PG&E Corporation and the Utility are working to resolve certain disputed general unsecured claims before a panel of mediators. On November 4, 2021, the Bankruptcy Court entered an order extending the deadline for PG&E Corporation and the Utility to object to claims to June 21, 2022, except for a claim filed by the California Department of Water Resources, for which the Bankruptcy Court set an objection deadline of March 23, 2022.

Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings were 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 recover on the Utility’s refund claims against these electricity suppliers. After the Utility received $145 million from the California Power Exchange and various escrows that were established as part of the disputed claims settlements in December 2021, the Utility filed at the Bankruptcy Court to close out its 2001 bankruptcy case. On December 22, 2021, the Bankruptcy Court granted the motion for entry of final decree and closed the 2001 bankruptcy case. As of December 31, 2021, the Consolidated Balance Sheets reflected $0 in net claims within Disputed claims and customer refunds compared to $242 million as of December 31, 2020. The Utility expects to refund current regulatory liabilities of $422 million, reflected in Current liabilities – other on the Consolidated Balance Sheets, $145 million of which would be funded from the amounts received from the California Power Exchange and various escrows discussed above.

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 $31 million and $53 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2021 as compared to $102 million and $400 million for PG&E Corporation and the Utility, respectively, during 2020.

Reorganization items, net for the year ended December 31, 2021 include the following:

	Year Ended December 31, 2021
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	21		(1)		20
Interest and other	(9)		—		(9)
Total reorganization items, net	$	12	$	(1)	$	11

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

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Reorganization items, net for the year ended December 31, 2020 include the following:

	Year Ended December 31, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	6	$	—	$	6
Legal and other (2)	318		1,651		1,969
Interest income	(14)		(2)		(16)
Total reorganization items, net	$	310	$	1,649	$	1,959

(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 from the Petition Date through December 31, 2019 include the following:

	Petition Date Through December 31, 2019
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	273		19		292
Interest income	(50)		(10)		(60)
Total reorganization items, net	$	320	$	26	$	346

(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

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, 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.  These differences have no impact on net income.  See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  As of December 31, 2020, the Utility also held restricted cash that primarily consisted of cash held in escrow to be used to pay bankruptcy related professional fees.

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Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the 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 GRCs, which occur every 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 Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility 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:

	Year Ended
(in millions)	2021		2020
Electric
Revenue from contracts with customers
Residential	$	6,089	$	5,523
Commercial	5,042		4,722
Industrial	1,493		1,530
Agricultural	1,565		1,471
Public street and highway lighting	73		69
Other (1)	(84)		(130)
Total revenue from contracts with customers - electric	14,178		13,185
Regulatory balancing accounts (2)	953		673
Total electric operating revenue	$	15,131	$	13,858
Natural gas
Revenue from contracts with customers
Residential	$	2,759	$	2,517
Commercial	713		597
Transportation service only	1,346		1,211
Other (1)	140		61
Total revenue from contracts with customers - gas	4,958		4,386
Regulatory balancing accounts (2)	553		225
Total natural gas operating revenue	5,511		4,611
Total operating revenues	$	20,642	$	18,469

(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.

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Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2021, PG&E Corporation and the Utility have identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates.

As of December 31, 2021, the allowance also included the estimated impact of the CAPP which offers financial assistance from the State of California for eligible customers in the form of a credit to the customer’s bill. The Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received on January 27, 2022.

As of December 31, 2021, the Utility recorded $209 million of long-term accounts receivables as a result of the CPUC’s June 30, 2021 final decision on bill debt relief which offers financial assistance for eligible customers in the form of a 24-month payment plan.

As of December 31, 2021, expected credit losses of $154 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. At December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

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. Wildfire fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 14 below. Wildfire fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of the claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for its available-for-sale debt securities. An impairment may exist if there is an intent to sell or a requirement to sell before recovery of the amortized basis. If such an impairment exists, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of December 31, 2021, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

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Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  See “AFUDC” below.  The Utility’s estimated service lives of its property, plant, and equipment were as follows:

	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2021		2020
Electricity generating facilities (1)	5 to 75	$	11,217	$	12,505
Electricity distribution facilities	10 to 70	37,723		34,902
Electricity transmission facilities	15 to 75	15,516		14,414
Natural gas distribution facilities	20 to 60	14,100		12,962
Natural gas transmission and storage facilities	5 to 66	9,067		8,293
Financing lease		18		18
Construction work in progress		3,480		2,757
General plant and other	5 to 50	7,838		8,041
Total property, plant, and equipment		98,959		93,892
Accumulated depreciation		(29,131)		(27,756)
Net property, plant, and equipment (2)		$	69,828	$	66,136

(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below.

(2) Includes $850 million of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below.

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.82% in 2021, 3.76% in 2020, and 3.80% in 2019.  The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $56 million and $133 million during 2021, $35 million and $140 million during 2020, and $55 million and $79 million during 2019.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2021 and 2020, including nuclear decommissioning obligations:

(in millions)	2021		2020
ARO liability at beginning of year	$	6,412	$	5,854
Liabilities incurred in the current period	—		268
Revision in estimated cash flows	(1,378)		53
Accretion	287		265
Liabilities settled	(23)		(28)
ARO liability at end of year	$	5,298	$	6,412

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The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding.  In December 2021, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly decreased its ARO liabilities by $1.4 billion. The adjustment was a result of a decrease in estimated costs based on refinements to the site-specific decommissioning analysis. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation accrued was $3.9 billion and $5.1 billion at December 31, 2021 and 2020, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $7.6 billion and $10.6 billion at December 31, 2021 and 2020, respectively.

Disallowance of Plant Costs

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

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC. 

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.

Variable Interest Entities

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

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Consolidated VIEs

Receivables Securitization Program

The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5 below) in October 2020 is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells 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, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets. As of December 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021 and 2020, the SPV had net accounts receivable of $3.3 billion and $2.6 billion, respectively, and outstanding borrowings of $974 million and $1.0 billion, respectively, under the Receivables Securitization Program.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Financing Order for AB 1054, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The recovery bonds are scheduled to pay principal and interest semi-annually on January 15 and July 15 of each year. The final scheduled payment date is July 15, 2046. Amounts owed to bond-holders are included in Long-term debt and Long-term debt, classified as current, on the Consolidated Balance Sheets.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021, PG&E Recovery Funding LLC has outstanding borrowings of $860 million.

Non-Consolidated VIEs

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 was the primary beneficiary of any of these VIEs at December 31, 2021, it 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 December 31, 2021, it did not consolidate any of them.

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Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054

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 customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as HFTDs 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).

On the Emergence 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. San Diego Gas & Electric Company and Southern California Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020 and 2021, the Utility made its second and third annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility have seven remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). 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.

As of December 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.1 billion in Other non-current liabilities, $461 million in current assets - Wildfire fund asset, and $5.3 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2021 and December 31, 2020, the Utility recorded amortization and accretion expense of $517 million and $413 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. 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 that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. 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 creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a five-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 have decreased the amortization period to six years. As of December 31, 2021, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by three years assuming greater effectiveness and would decrease the amortization period by two 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 and determination of any amounts required to be reimbursed to the Wildfire Fund, 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.

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PG&E Corporation and the Utility evaluate all assumptions quarterly, and 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 assess the Wildfire Fund asset for acceleration of the amortization of the asset 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 acceleration of the amortization of the asset 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. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire and $43 million of accelerated amortization, reflected in Wildfire Fund expense.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, and “Contingencies and Commitments” in Notes 14 and 15 below.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2021 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(39)	$	17	$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)	1,007		137		1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)	(1,003)		(136)		(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively) (1)	4		(24)		(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)	2		14		16
Net current period other comprehensive income	6		1		7
Ending balance	$	(33)	$	18	$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details. 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(22)	$	17	$	(5)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively)	(417)		170		(247)
Regulatory account transfer (net of taxes of $155 and $66, respectively)	400		(170)		230
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $1 and $6, respectively)(1)	2		(15)		(13)
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1)	2		5		7
Net current period other comprehensive loss	(17)		—		(17)
Ending balance	$	(39)	$	17	$	(22)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

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Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

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

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2021 and 2020.

For the years ended December 31, 2021 and 2020, the Utility made total cash payments, including fixed and variable, of $2.4 billion and $2.5 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements.

At December 31, 2021 and 2020, the Utility’s operating leases had a weighted average remaining lease term of 6.04 years and 5.7 years and a weighted average discount rate of 6.1% and 6.2%, respectively.

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

	Year Ended December 31,
(in millions)	2021		2020
Operating lease fixed cost	$	578	$	679
Operating lease variable cost	1,782		1,852
Total operating lease costs	$	2,360	$	2,531

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At December 31, 2021, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2021
2022	$	533
2023	276
2024	118
2025	111
2026	105
Thereafter	444
Total lease payments	1,587
Less imputed interest	(310)
Total	$	1,277

Sale of Transmission Tower Wireless Licenses

On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers.

The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.

The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market additional attachment locations on up to 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.

In addition, the Utility and SBA entered into a Pipeline Cell Site Transaction Agreement pursuant to which the Utility and SBA established terms and conditions for adding additional cell sites under the License Agreement. Pipeline Cell Sites are locations where the Utility was in the process of locating a new Cell Site for a wireless carrier at the close of the transaction.

In exchange for the exclusive license and entry into the License Agreement, SBA paid the Utility $946 million of the purchase price at the closing. On August 15, 2021, the post-closing period ended, and the final purchase price was $947 million, pursuant to the terms of the Transaction Agreement.

The Utility recorded approximately $370 million of the $947 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $947 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement, represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a third-party discounted cash flow model based on business assumptions and estimates to determine the allocation of the purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are included in Other noncurrent liabilities on the Consolidated Balance Sheets.

The Utility recorded the remaining approximately $471 million ($455 million of which was noncurrent) of the sale proceeds to regulatory liabilities, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices.

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The financing obligation is amortized through Electric operating revenue and Interest expense on the Consolidated Statements of Income using the effective interest method and the deferred revenue balance is amortized through Electric operating revenue ratably over the 100-year term.

Recently Adopted Accounting Standards

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 adopted this ASU on January 1, 2021. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Government Assistance

In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance, which increases the transparency of government assistance including the disclosure of (1) the types of assistance, (2) an entity’s accounting for the assistance, and (3) the effect of the assistance on an entity’s financial statements. PG&E Corporation and the Utility adopted this ASU as of December 31, 2021. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

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 became effective for PG&E Corporation and the Utility on January 1, 2022 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.

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NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2021		2020
Pension benefits (1)	$	708	$	2,245	Indefinitely
Environmental compliance costs	1,089		1,112		32 years
Utility retained generation (2)	133		181		6 years
Price risk management	216		204		19 years
Unamortized loss, net of gain, on reacquired debt	37		49		23 years
Catastrophic event memorandum account (3)	1,119		842		1 - 3 years
Wildfire expense memorandum account (4)	347		400		TBD years
Fire hazard prevention memorandum account (5)	75		137		1 - 3 years
Fire risk mitigation memorandum account (6)	44		66		1 - 3 years
Wildfire mitigation plan memorandum account (7)	424		390		1 - 3 years
Deferred income taxes (8)	1,849		908		51 years
Insurance premium costs (9)	207		294		3 - 4 years
Wildfire mitigation balancing account (10)	273		156		1 - 3 years
General rate case memorandum accounts (11)	—		376		1 - 2 years
Vegetation management balancing account (12)	1,411		592		1 - 3 years
COVID-19 pandemic protection memorandum accounts (13)	49		84		TBD years
Other	1,226		942		Various
Total long-term regulatory assets	$	9,207	$	8,978

(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 December 31, 2021 and 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Balance as of December 31, 2021 represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire. Balance as of December 31, 2020 is comprised of incremental wildfire liability insurance premium costs for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is 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 is subject to CPUC review and approval.

(6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through December 31, 2021. Recovery of WMPMA costs is 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 excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2021. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) The GRC memorandum accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered through rates over 22 months, beginning March 1, 2021.

(12) Represents costs from routine vegetation management and EVM activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA for the period January 1, 2020 through December 31, 2021. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.

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(13) On April 16, 2020, the CPUC passed a resolution that established the 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 certain residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2021, the Utility had recorded an under-collection of $30 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA was in effect. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2021		2020
Cost of removal obligations (1)	$	7,306	$	6,905
Recoveries in excess of AROs (2)	388		458
Public purpose programs (3)	946		948
Employee benefit plans (4)	1,229		995
Transmission tower wireless licenses (5)	446		—
SFGO sale (6)	343		—
Other	1,341		1,118
Total long-term regulatory liabilities	$	11,999	$	10,424

(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 11 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.

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $446 million, $311 million and $135 million will be refunded to FERC and CPUC jurisdiction customers, respectively. See Note 3 above.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period, beginning in 2022.

Regulatory Balancing Accounts

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

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

	Receivable Balance at December 31,
(in millions)	2021		2020
Gas distribution and transmission	$	—	$	102
Energy procurement	310		413
Public purpose programs	321		292
Fire hazard prevention memorandum account	50		121
Fire risk mitigation memorandum account	14		33
Wildfire mitigation plan memorandum account	67		161
Wildfire mitigation balancing account	91		27
General rate case memorandum accounts	468		313
Vegetation management balancing account	127		115
Insurance premium costs	605		135
Wildfire expense memorandum account	440		—
Residential uncollectibles balancing accounts	127		—
Other	379		289
Total regulatory balancing accounts receivable	$	2,999	$	2,001

	Payable Balance at December 31,
(in millions)	2021		2020
Electric distribution	$	121	$	55
Electric transmission	24		267
Gas distribution and transmission	83		76
Energy procurement	211		158
Public purpose programs	259		410
Nuclear decommissioning adjustment mechanism	137		—
Other	286		279
Total regulatory balancing accounts payable	$	1,121	$	1,245

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case.  Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities.  Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency. The FHPMA tracks costs that protect the public from potential fire hazards. The FRMMA and WMPMA balances track costs that are recoverable within 12 months as requested in the 2020 WMCE application. The WMBA tracks costs associated with wildfire mitigation revenue requirement activities. The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC. The VMBA tracks routine and EVM activities. The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2021, there was $82 million in insurance premium costs recorded in Current regulatory assets. The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022. The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. The nuclear decommissioning adjustment mechanism tracks costs related to the closure of the Diablo Canyon power plant.

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NOTE 5: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2021:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding			Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2026	$	4,000	(1)	$	1,885		$	692	$	1,423
Utility term loan credit facility	October 2022 (2)	1,441		(2)	1,441		(2)	—		—
Utility receivables securitization program (3)	September 2023	1,000		(4)	974			—		—		(4)
PG&E Corporation revolving credit facility	June 2024	500			—			—		500
Total credit facilities		$	6,941		$	4,300		$	692	$	1,923

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

(2 On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022.

(3) On October 5, 2020, the Utility 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 the SPV, a limited liability company wholly owned by the Utility. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023. For more information, see “Variable Interest Entities” in Note 3 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program. As of December 31, 2021, the Receivables Securitization Program had a maximum borrowing base of $974 million and was fully drawn.

Utility

As previously disclosed, on July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.

As previously disclosed, on June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.

As previously disclosed, on July 1, 2020, the Utility entered into a $3.0 billion term loan credit agreement (the “Utility Term Loan Credit Agreement”) comprised of 364-day tranche loans in the aggregate principal amount of $1.5 billion (the “364-Day Tranche Loans”) and 18-month tranche loans in the aggregate principal amount of $1.5 billion (the “18-Month Tranche Loans”). As previously disclosed, the 364-Day Tranche Loans were paid in full on March 11, 2021. The 18-Month Tranche Loans had an initial maturity date of 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.

On October 29, 2021 and on December 31, 2021, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to October 1, 2022. On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022. To the extent that any 18-Month Tranche Loans remain outstanding on April 1, 2022, a fee will be due and owing to the lenders holding such 18-Month Tranche Loans.

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PG&E Corporation

As previously disclosed, on July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

As previously disclosed, on June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.

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

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. The intercompany note includes usual and customary provisions for notes of this type. The interest rate on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization, pursuant to AB 1054, for a transaction to finance, using securitization, up to $1.19 billion of fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021, with the final amount to be financed based on the capital expenditures incurred by the Utility prior to the securitization transaction. On June 24, 2021, the CPUC issued a financing order authorizing the issuance of up to approximately $1.2 billion of recovery bonds to recover up to $1.19 billion of fire risk mitigation capital expenditures plus an estimated $13.3 million in related upfront financing costs. On July 6, 2021, the financing order became final and non-appealable.

On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The net proceeds were used to fund fire risk mitigation capital expenditures that have been incurred by the Utility and incurred by PG&E Corporation on behalf of the Utility in 2020 and 2021.

For more information on PG&E Recovery Fund LLC, see “Variable Interest Entities” in Note 3 above.

SB 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers 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.

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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 finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact amounts billed to customers, with the proceeds of the securitization used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. In connection with the proposed transaction, the Utility would retire $6.0 billion of Utility debt. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. The decision is being challenged by TURN.

Short-Term Debt Issuance

On November 15, 2021, the Utility completed the sale of $300 million aggregate principal amount of Floating Rate First Mortgage Bonds due November 14, 2022. The proceeds, along with the long-term debt proceeds from the First Mortgage Bonds also issued on November 15, 2021, were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021.

Long-Term Debt Issuances and Redemptions

Utility

In March 2021, the Utility issued (i) $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, (ii) $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and (iii) $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s Term Loan Credit Agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement and (iii) general corporate purposes.

In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On November 15, 2021, the Utility completed the sale of (i) $900 million aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 and (ii) an additional $550 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 (the “2031 Bonds”). The 2031 Bonds are part of the same series of debt securities issued by the Utility in March 2021. The proceeds were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021. The Utility used the remaining net proceeds for general corporate purposes, including the repayment of approximately $300 million of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

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

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2021		December 31, 2020
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,709	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of debt issuance costs		(26)		—
Unamortized discount, net of premium and debt issuance costs		(90)		(85)
Total PG&E Corporation Long-Term Debt		4,593		4,624
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	500		500
2022	1.75%	2,500		2,500
2023	1.37% - 4.25%	3,575		1,175
2024	3.40% - 3.75%	800		800
2025	3.45% - 3.50%	1,475		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 3.30%	2,550		2,550
2028	3.00% - 4.65%	1,975		1,175
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		2,000
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		250
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
Less: current portion, net of debt issuance costs		(2,996)		—
Unamortized discount, net of premium and debt issuance costs		(190)		(182)
Total Utility First Mortgage Bonds		31,816		30,170
Recovery Bonds	1.46% - 2.82%	860		—
Less: current portion		(18)		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2023	variable rate (3)	974		1,000
18-month Term Loan - Stated Maturity: 2022	variable rate (4)	1,441		1,500
Less: current portion		(1,441)		—
Unamortized discount, net of premium and debt issuance costs		—		(6)
Total Utility Long-Term Debt		33,632		32,664
Total PG&E Corporation Consolidated Long-Term Debt		$	38,225	$	37,288

(1) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 3.50% and 5.50%, respectively.

(2) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69% and 1.70%, respectively.

(3) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.30% and 1.57%, respectively.

(4) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 2.38% and 2.44%, respectively.

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Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2021 are reflected in the table below:

(in millions, except interest rates)	2022			2023			2024			2025			2026			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2021	3.50		%	3.50		%	3.50		%	3.50		%	—		%	—		%	3.50		%
Variable rate obligations	$	28		$	28		$	28		$	2,625		$	—		$	—		$	2,709
Utility
Average fixed interest rate	1.75		%	2.26		%	3.60		%	3.47		%	3.10		%	3.90		%	3.49		%
Fixed rate obligations	$	2,500		$	3,575		$	800		$	1,475		$	2,551		$	23,601		$	34,502
Variable interest rate as of December 31, 2021	2.20		%	various (1)			—		%	—		%	—		%	—		%	various (1)
Variable rate obligations	$	1,941		$	974		$	—		$	—		$	—		$	—		$	2,915
Total consolidated debt	$	4,469		$	4,577		$	828		$	4,100		$	2,551		$	25,601		$	42,126

(1) At December 31, 2021, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.30%, 1.69% and 2.38% respectively.

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 1,985,400,540 shares of common stock outstanding at December 31, 2021, which excludes 477,743,590 shares of common stock issued to ShareCo.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2021.

Equity Offerings

During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 138 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the equity units purchase contracts and subject to certain adjustments as provided therein. The settlement date of the equity unit purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts.

At the Market Equity Distribution Program

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement.

The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement.

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During the year ended December 31, 2021, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement. As of December 31, 2021, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings.

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 DTAs to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent 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). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into an agreement (the “Share Exchange and Tax Matters Agreement”), pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,463,891,104 shares outstanding as of February 4, 2022, only 1,548,403,924 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2022 was 2.98% of the outstanding shares. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares.

As of the date of this report, it is more likely than not that PG&E Corporation has not 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.

Share Exchange and Tax Matters Agreement

In accordance with the Share Exchange and Tax Matters Agreement, the grantor trust election has been filed.

With the grantor trust election, the Utility’s tax deductions occur as and when the Fire Victim Trust pays the fire victims rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. For PG&E Corporation common stock transferred to the Fire Victim Trust, the amount of the tax deduction will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust.

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Under the Share Exchange and Tax Matters Agreement, the parties agreed to exchange the 477,743,590 shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan (the “Plan Shares”) for an equal number of newly-issued shares of PG&E Corporation common stock (the “New Shares”). Accordingly, on July 9, 2021, PG&E Corporation issued 477,743,590 New Shares to ShareCo, which has the sole purpose of holding the New Shares in a designated brokerage account to facilitate the exchange process. When the Fire Victim Trust desires to sell any or all of its Plan Shares, the Fire Victim Trust may exchange any number of Plan Shares for a corresponding number of New Shares on a share-for-share basis (without any further consideration payable by either party) and thereafter promptly dispose of the New Shares in one or more transactions with one or more third parties. In the event that the Fire Victim Trust is unable to timely dispose of New Shares under certain circumstances (such shares, the “Nonconforming New Shares”), PG&E Corporation has authorized up to 250,000,000 additional shares of PG&E Corporation common stock, which may be transferred by ShareCo to the Fire Victim Trust on behalf of the Utility, in exchange for the Nonconforming New Shares, following the same procedures as for an exchange of Plan Shares for New Shares. The Plan Shares and any Non-Conforming New Shares exchanged will be held thereafter by the Utility. In the event that the Fire Victim Trust disposes of any share of PG&E Corporation’s common stock subject to the Share Exchange and Tax Matters Agreement without complying with the terms of the agreement, the Fire Victim Trust may be required to make a payment to the Utility designed to compensate the Utility for adverse tax consequences arising from nonconforming sale transactions.

Upon PG&E Corporation’s issuance of the New Shares to ShareCo, PG&E Corporation’s common stock increased by $4.85 billion, the fair value of the shares on July 9, 2021. The increase to common stock is fully offset by the fair value of treasury stock recorded. The issuance of the New Shares did not have an impact on the total number of outstanding common shares as the New Shares are currently held by ShareCo and as such, there was no impact on basic or diluted EPS for the year ended December 31, 2021.

When the Fire Victim Trust notifies the Utility that it intends to sell shares, ShareCo (on behalf of the Utility) will transfer the New Shares to the Fire Victim Trust, and the Fire Victim Trust will transfer the Plan Shares to the Utility. The Utility has no plan or intention to dispose of the Plan Shares at any time. As shares are exchanged with the Fire Victim Trust, the Utility will record the cost of shares and PG&E Corporation’s investment under additional paid in capital and PG&E Corporation’s common stock and treasury stock will decrease by the fair value per share established on July 9, 2021.

As of December 31, 2021, none of the 250,000,000 reserved shares had been issued.

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 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.  As of January 31, 2022, there were $59.1 million of such cumulative and unpaid dividends on the Utility’s preferred stock. 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 emergence from Chapter 11.  

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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. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. It is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock.

Long-Term Incentive Plan

The LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 58,552,722 shares were available for future awards at December 31, 2021.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2021:

(in millions)	2021		2020		2019
Stock Options	$	—	$	3	$	7
Restricted stock units	35		15		21
Performance shares	21		17		22
Total compensation expense (pre-tax)	$	56	$	35	$	50
Total compensation expense (after-tax)	$	40	$	25	$	35

Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant.  Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2021, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. No stock options were granted in 2021 and 2020.  

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the date of grant.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2021.

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The following table summarizes stock option activity for PG&E Corporation and the Utility for 2021:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,221,247	$	7.45		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(25,413)	10.23			—
Outstanding at December 31	2,195,834	7.42		4.33	—
Vested or expected to vest at December 31	2,195,834	7.42		4.33	—
Exercisable at December 31	2,195,834	$	7.42	4.33	$	—

(1) Represents additional payout of existing stock option grants.

Restricted Stock Units

Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2021, 2020, and 2019 was $11.01, $9.25, and $18.57, respectively.  The total fair value of restricted stock units that vested during 2021, 2020, and 2019 was $19 million, $31 million, and $42 million, respectively.  The tax detriment from restricted stock units that vested in 2021 was $11 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2021, $81 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 2.19 years.

The following table summarizes restricted stock unit activity for 2021:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	890,353	$	23.05
Granted	10,352,117	11.01
Vested	(743,672)	25.20
Forfeited	(408,423)	11.67
Nonvested at December 31	10,090,375	$	11.00

Performance Shares

Performance shares generally will vest three years after the grant date.  Following vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR).  Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards.  The weighted average grant-date fair value for performance shares granted during 2021, 2020, and 2019 was $11.83, $9.62, and $15.39 respectively.  The tax detriment from performance shares that vested in 2021 was $19 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2021, $50 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.47 years.

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The following table summarizes activity for performance shares in 2021:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	7,288,782	$	9.16
Granted	2,714,645	11.83
Vested	—	—
Forfeited (1)	(1,436,418)	11.35
Nonvested at December 31	8,567,009	$	9.64

(1) Includes performance shares that expired with zero value as performance targets were not met.

NOTE 7: PREFERRED STOCK

PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share.  At December 31, 2021 and 2020, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share, respectively.  The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

On December 31, 2021, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2021, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022.

NOTE 8: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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 (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2021, 2020, and 2019.

	Year Ended December 31,
(in millions, except per share amounts)	2021		2020		2019
Loss attributable to common shareholders	$	(102)	$	(1,318)	$	(7,656)
Weighted average common shares outstanding, basic	1,985		1,257		528
Add incremental shares from assumed conversions:
Employee share-based compensation	—		—		—
Equity Units	—		—		—
Weighted average common share outstanding, diluted	1,985		1,257		528
Total Loss per common share, diluted	$	(0.05)	$	(1.05)	$	(14.50)

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

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NOTE 9: INCOME TAXES

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating DTAs and liabilities.  DTAs and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the technical merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. 

Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. 

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2021		2020		2019		2021		2020		2019
Current:
Federal	$	—	$	(26)	$	1	$	—	$	(26)	$	4
State	1		(34)		101		—		(34)		94
Deferred:
Federal	543		258		(2,361)		588		290		(2,363)
State	296		171		(1,136)		316		185		(1,137)
Tax credits	(4)		(7)		(5)		(4)		(7)		(5)
Income tax provision (benefit)	$	836	$	362	$	(3,400)	$	900	$	408	$	(3,407)

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The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2021		2020		2021		2020
Deferred income tax assets:
Tax carryforwards	$	5,628	$	7,641	$	5,425	$	7,529
Compensation	185		187		108		109
Wildfire-related claims (1)	1,723		544		1,723		544
Operating lease liability	346		489		346		488
Transmission tower wireless licenses	266		—		266		—
Other (2)	278		212		293		219
Total deferred income tax assets	$	8,426	$	9,073	$	8,161	$	8,889
Deferred income tax liabilities:
Property related basis differences	8,847		8,311		8,835		8,300
Regulatory balancing accounts	1,193		763		1,193		763
Debt financing costs	501		526		501		526
Operating lease right of use asset	346		489		346		488
Income tax regulatory asset (3)	517		254		517		254
Other (4)	199		128		178		128
Total deferred income tax liabilities	$	11,603	$	10,471	$	11,570	$	10,459
Total net deferred income tax liabilities	$	3,177	$	1,398	$	3,409	$	1,570

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service territory over the past several years.

(2) Amounts include benefits, environmental reserve, and customer advances for construction. 

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.

(4) Amount primarily includes an environmental reserve.

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

	PG&E Corporation						Utility
	Year Ended December 31,
	2021		2020		2019		2021		2020		2019
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	31.3		(15.3)		7.5		24.1		19.1		7.5
Effect of regulatory treatment of fixed asset differences (2)	(71.5)		39.0		2.8		(51.6)		(44.9)		2.8
Tax credits	(1.7)		1.5		0.1		(1.2)		(1.7)		0.1
Fire Victim Trust (3)	127.3		(44.9)		—		91.9		51.7		—
Bankruptcy and emergence	—		(37.6)		—		—		2.4		—
Other, net (4)	5.3		(2.1)		(0.6)		2.6		2.2		(0.5)
Effective tax rate	111.7	%	(38.4)	%	30.8	%	86.8	%	49.8	%	30.9	%

(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 2021, 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) The Utility includes an adjustment for a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for 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 in 2020. PG&E Corporation includes the same adjustment as the Utility in 2021 and 2020 as well as a permanent non-deductible equity backstop premium expense in 2020. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively in 2020, accounts for the remaining difference.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs in 2021 and 2020.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2021		2020		2019		2021		2020		2019
Balance at beginning of year	$	437	$	420	$	377	$	437	$	420	$	377
Reductions for tax position taken during a prior year	(23)		(43)		(1)		(23)		(43)		(1)
Additions for tax position taken during the current year	85		60		44		85		60		44
Settlements	(1)		—		—		(1)		—		—
Balance at end of year	$	498	$	437	$	420	$	498	$	437	$	420

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2021 for PG&E Corporation and the Utility was $30 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2021, 2020, and 2019, these amounts were immaterial.

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Tax Settlements

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010.

PG&E Corporation’s tax returns have been accepted through 2014 for California income tax purposes. Tax years 2015 and thereafter remain subject to examination by the State of California.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

(in millions)	December 31, 2021		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,600	2031 - 2036
Net operating loss carryforward - Post-2017	17,467		N/A
Tax credit carryforward	144		2029 - 2041
State:
Net operating loss carryforward	$	18,853	2039 - 2041
Tax credit carryforward	122		Various

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

Other Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. At December 31, 2021, it is reasonably possible that within the next 12 months, unrecognized tax benefits will decrease. The amount is not expected to be material.

As of the date of this report, it is more likely than not that PG&E Corporation has not 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 have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. Half of the payment was paid in 2021.

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 Consolidated Financial Statements due to this legislation.

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Additionally, as a result of the grantor trust election, the Utility’s tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation’s net operating loss has decreased by approximately $10.0 billion, which will be offset by payments made by the Fire Victim Trust to the fire victims (which totaled approximately $1.67 billion in 2021) and the net activities of the Fire Victim Trust to date. Additionally, there was a $1.3 billion charge, net of tax, decreasing net DTAs for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Consolidated Financial Statements for activity through December 31, 2020. PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact in PG&E Corporation’s and the Utility’s consolidated financial statements for the year ended December 31, 2021. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares. For more information, see Note 6 above.

NOTE 10: 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 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 Consolidated Balance Sheets and 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 Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through 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 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 Consolidated Balance Sheets at fair value. 

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Volume of Derivative Activity

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

		Contract Volume
		At December 31,
Underlying Product	Instruments	2021	2020
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	173,361,635	146,642,863
	Options	14,420,000	14,140,000
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	10,283,639	9,435,830
	Options	288,000	—
	Congestion Revenue Rights (3)	239,857,610	266,091,470

(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 December 31, 2021, 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	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

At December 31, 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	$	33	$	—	$	115	$	148
Other noncurrent assets – other	136		—		—		136
Current liabilities – other	(38)		—		15		(23)
Noncurrent liabilities – other	(204)		—		10		(194)
Total commodity risk	$	(73)	$	—	$	140	$	67

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

Some 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. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2021, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 11: 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.

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

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

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

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

	Fair Value Measurements
	At December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	289	$	—	$	—	$	—	$	289
Nuclear decommissioning trusts
Short-term investments	22		—		—		—		22
Global equity securities	2,504		—		—		—		2,504
Fixed-income securities	1,158		866		—		—		2,024
Assets measured at NAV	—		—		—		—		31
Total nuclear decommissioning trusts (2)	3,684		866		—		—		4,581
Price risk management instruments (Note 10)
Electricity	—		9		214		6		229
Gas	—		4		—		137		141
Total price risk management instruments	—		13		214		143		370
Rabbi trusts
Fixed-income securities	—		104		—		—		104
Life insurance contracts	—		76		—		—		76
Total rabbi trusts	—		180		—		—		180
Long-term disability trust
Short-term investments	6		—		—		—		6
Assets measured at NAV	—		—		—		—		132
Total long-term disability trust	6		—		—		—		138
TOTAL ASSETS	$	3,979	$	1,059	$	214	$	143	$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	11	$	248	$	(24)	$	235
Gas	—		10		—		(3)		7
TOTAL LIABILITIES	$	—	$	21	$	248	$	(27)	$	242

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

(2) Represents amount before deducting $783 million, primarily related to deferred taxes on appreciation of investment value. 

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	Fair Value Measurements
	At December 31, 2020
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	470	$	—	$	—	$	—	$	470
Nuclear decommissioning trusts
Short-term investments	27		—		—		—		27
Global equity securities	2,398		—		—		—		2,398
Fixed-income securities	924		835		—		—		1,759
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,349		835		—		—		4,209
Price risk management instruments (Note 10)
Electricity	—		2		166		2		170
Gas	—		1		—		113		114
Total price risk management instruments	—		3		166		115		284
Rabbi trusts
Fixed-income securities	—		106		—		—		106
Life insurance contracts	—		79		—		—		79
Total rabbi trusts	—		185		—		—		185
Long-term disability trust
Short-term investments	9		—		—		—		9
Assets measured at NAV	—		—		—		—		158
Total long-term disability trust	9		—		—		—		167
TOTAL ASSETS	$	3,828	$	1,023	$	166	$	115	$	5,315
Liabilities:
Price risk management instruments (Note 10)
Electricity	—		1		238		(25)		214
Gas	—		3		—		—		3
TOTAL LIABILITIES	$	—	$	4	$	238	$	(25)	$	217

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

(2) Represents amount before deducting $671 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 years ended December 31, 2021 and 2020.

Trust Assets

Assets Measured at Fair Value

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

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

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

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the 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, credit 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.  The Utility 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 rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  See Note 10 above.

	Fair Value at
(in millions)	At December 31, 2021				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	188	$	93	Market approach	CRR auction prices	$ (40.77) - 2,265.94 / 0.40
Power purchase agreements	$	26	$	155	Discounted cash flow	Forward prices	$ (7.97) - 256.20 / 47.17

(1) Represents price per megawatt-hour.

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

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	Fair Value at
(in millions)	At December 31, 2020				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	153	$	74	Market approach	CRR auction prices	$ (320.25) - 320.25 / 0.30
Power purchase agreements	$	13	$	164	Discounted cash flow	Forward prices	$ 12.56 - 148.30 / 35.52

(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 price risk management instruments for the years ended December 31, 2021 and 2020, respectively:

	Price Risk Management Instruments
(in millions)	2021		2020
Asset (liability) balance as of January 1	$	(72)	$	5
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	38		(77)
Asset (liability) balance as of December 31	$	(34)	$	(72)

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

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2021 and 2020, 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 December 31,
	2021				2020
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,619	$	4,796	$	1,901	$	2,175
Utility	31,816		35,803		29,664		32,632

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Nuclear Decommissioning Trust Investments

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

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments	$	22	$	—	$	—	$	22
Global equity securities	479		2,066		(10)		2,535
Fixed-income securities	1,938		98		(12)		2,024
Total (1)	$	2,439	$	2,164	$	(22)	$	4,581
As of December 31, 2020
Nuclear decommissioning trusts
Short-term investments	$	27	$	—	$	—	$	27
Global equity securities	543		1,881		(1)		2,423
Fixed-income securities	1,610		152		(3)		1,759
Total (1)	$	2,180	$	2,033	$	(4)	$	4,209

(1) Represents amounts before deducting $783 million and $671 million at December 31, 2021 and 2020, 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)	December 31, 2021
Less than 1 year	$	97
1–5 years	495
5–10 years	480
More than 10 years	952
Total maturities of fixed-income securities	$	2,024

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

(in millions)	2021		2020		2019
Proceeds from sales and maturities of nuclear decommissioning investments	$	1,678	$	1,518	$	956
Gross realized gains on securities	286		159		69
Gross realized losses on securities	(19)		(41)		(14)

NOTE 12: EMPLOYEE BENEFIT PLANS

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  Certain trusts underlying these plans are qualified trusts under the IRC.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  On an annual basis, the Utility funds the pension plan up to the amount it is authorized to recover through rates.

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

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Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2021 and 2020:

Pension Plan

(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	20,759	$	18,547
Actual return on plan assets	1,693		2,736
Company contributions	335		343
Benefits and expenses paid	(892)		(867)
Fair value of plan assets at end of year	$	21,895	$	20,759
Change in benefit obligation:
Benefit obligation at beginning of year	$	23,172	$	20,525
Service cost for benefits earned	587		530
Interest cost	645		713
Actuarial (gain) loss (1)	(752)		2,271
Plan amendments	—		—
Benefits and expenses paid	(893)		(867)
Benefit obligation at end of year (2)	$	22,759	$	23,172
Funded Status:
Current liability	$	(9)	$	(3)
Noncurrent liability	(856)		(2,410)
Net liability at end of year	$	(865)	$	(2,413)

(1) The actuarial gain for the year ended December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions. The actuarial loss for the year ended December 31, 2020 was due to a decrease in the discount rate used to measure the projected benefit obligation.

(2) PG&E Corporation’s accumulated benefit obligation was $20.4 billion and $20.7 billion at December 31, 2021 and 2020, respectively.

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Postretirement Benefits Other than Pensions

(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,995	$	2,678
Actual return on plan assets	193		379
Company contributions	10		26
Plan participant contribution	80		81
Benefits and expenses paid	(176)		(169)
Fair value of plan assets at end of year	$	3,102	$	2,995
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,876	$	1,832
Service cost for benefits earned	63		61
Interest cost	51		63
Actuarial gain (1)	(152)		(14)
Benefits and expenses paid	(156)		(149)
Federal subsidy on benefits paid	4		3
Plan participant contributions	80		80
Benefit obligation at end of year	$	1,766	$	1,876
Funded Status: (2)
Noncurrent asset	$	1,340	$	1,153
Noncurrent liability	(4)		(34)
Net asset at end of year	$	1,336	$	1,119

(1) The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes. The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation.

(2) At December 31, 2021 and 2020, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $363 million and $359 million as of December 31, 2021, and $377 million and $343 million as of December 31, 2020, respectively.

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

Components of Net Periodic Benefit Cost

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.

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Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan

(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	587	$	530	$	443
Interest cost	645		713		758
Expected return on plan assets	(1,046)		(1,044)		(906)
Amortization of prior service cost	(6)		(6)		(6)
Amortization of net actuarial loss	6		3		3
Net periodic benefit cost	186		196		292
Less: transfer to regulatory account (2)	147		136		42
Total expense recognized	$	333	$	332	$	334

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

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions

(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	63	$	61	$	56
Interest cost	51		63		76
Expected return on plan assets	(137)		(138)		(123)
Amortization of prior service cost	14		14		14
Amortization of net actuarial loss	(33)		(21)		(3)
Net periodic benefit cost	$	(42)	$	(21)	$	20

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

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

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

Components of Accumulated Other Comprehensive Income

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions.  For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income.  For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income.  As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

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Valuation Assumptions

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2021		2020		2019		2021	2020	2019
Discount rate	3.03	%	2.77	%	3.46	%	2.97 - 3.04%	2.67 - 2.80 %	3.37 - 3.47%
Rate of future compensation increases	3.80	%	3.80	%	3.90	%	N/A	N/A	N/A
Expected return on plan assets	5.50	%	5.10	%	5.70	%	3.30 - 6.40%	3.10 - 6.10 %	3.50 - 6.60%
Interest crediting rate for cash balance plan	1.95	%	1.95	%	2.11	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2021 was 6.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond. 

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 5.5% compares to a ten-year actual return of 9.6%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 817 Aa-grade non-callable bonds at December 31, 2021.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility.  In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios. 

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.

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The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

	Pension Plan						PBOP Plans
	2022		2021		2020		2022		2021		2020
Global equity securities	30	%	30	%	30	%	26	%	36	%	28	%
Absolute return	2	%	2	%	2	%	1	%	1	%	2	%
Real assets	8	%	8	%	8	%	3	%	5	%	8	%
Fixed-income securities	60	%	60	%	60	%	70	%	58	%	62	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2021 and 2020. 

	Fair Value Measurements
	At December 31,
	2021								2020
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	552	$	255	$	—	$	807	$	334	$	408	$	—	$	742
Global equity securities	2,074		424		—		2,498		1,875		—		—		1,875
Absolute Return	—		1		—		1		1		1		—		2
Real assets	632		—		—		632		517		—		—		517
Fixed-income securities	2,729		7,388		27		10,144		2,467		7,154		12		9,633
Assets measured at NAV	—		—		—		7,972		—		—		—		8,224
Total	$	5,987	$	8,068	$	27	$	22,054	$	5,194	$	7,563	$	12	$	20,993
PBOP Plans:
Short-term investments	$	31	$	—	$	—	$	31	$	37	$	—	$	—	$	37
Global equity securities	105		—		—		105		173		—		—		173
Real assets	34		—		—		34		54		—		—		54
Fixed-income securities	776		875		1		1,652		481		715		1		1,197
Assets measured at NAV	—		—		—		1,296		—		—		—		1,549
Total	$	946	$	875	$	1	$	3,118	$	745	$	715	$	1	$	3,010
Total plan assets at fair value							$	25,172							$	24,003

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $175 million and $249 million at December 31, 2021 and 2020, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. 

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a NAV per share can be redeemed quarterly with a notice not to exceed 90 days.

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Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity Securities

The global equity category includes investments in common stock and equity-index futures.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Real Assets

The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. 

Fixed-Income Securities

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt 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 trusts 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 Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2021 and 2020.

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Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2021 and 2020:

(in millions)
For the year ended December 31, 2021	Fixed-Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date	6
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	22
Settlements	(6)
Balance at end of year	$	27
(in millions)
For the year ended December 31, 2020	Fixed-Income
Balance at beginning of year	$	15
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(3)
Purchases, issuances, sales, and settlements:
Purchases	11
Settlements	(13)
Balance at end of year	$	12

There were no material transfers out of Level 3 in 2021 and 2020.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $335 million to the pension benefit plans and $10 million to the other benefit plans in 2021.  These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements.  None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2021.  The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2022. 

Benefits Payments and Receipts

As of December 31, 2021, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2022	869	81	(3)
2023	954	85	(3)
2024	988	89	(3)
2025	1018	88	(3)
2026	1,046	91	(3)
Thereafter in the succeeding five years	5,533	466	(3)

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There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $133 million, $119 million, and $109 million in 2021, 2020, and 2019, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves.  The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services.  PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies.  Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2021		2020		2019
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	4
Utility expenses from:
Administrative services received from PG&E Corporation	$	82	$	108	$	107
Utility employee benefit due to PG&E Corporation	39		34		42

At December 31, 2021 and 2020, the Utility had receivables of $173 million and $35 million, respectively, from PG&E Corporation included in Accounts receivable – other and Noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $19 million and $46 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet. For more information, see “Intercompany Note Payable” in Note 5 above.

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NOTE 14: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

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 (including those during mediations with claimants), 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.

The process for estimating losses associated with potential claims related to wildfires 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, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the 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 courts or other governmental entities.

Criminal charges have been filed against the Utility in connection with the 2019 Kincade fire and the 2020 Zogg fire. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. In the event that the Utility were convicted of certain charges in connection with the 2019 Kincade fire or 2020 Zogg fire, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with such fire would materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the courts presiding over the criminal proceedings.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints 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 relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

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If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, 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 through rates. 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. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and 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 in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts 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 and the outcome of the criminal proceedings initiated against the Utility. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of 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 the possession of Cal Fire or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. 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 July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

On April 6, 2021, the Sonoma County District Attorney’s office filed the Kincade Complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Kincade Complaint. It further announced that it would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the Kincade Complaint. At a hearing on September 9, 2021, the Sonoma County Superior Court overruled the demurrer. The Utility pled not guilty to all charges on October 13, 2021. On January 28, 2022, the Sonoma County District Attorney’s Office filed the Kincade Amended Complaint, which replaces two felonies with five different felonies and drops six misdemeanor counts. On January 28, 2022, the court deemed the Utility’s demurrer and the court’s prior ruling as applying to 22 of the 30 counts in the Kincade Amended Complaint, and the Utility thereafter pled not guilty to all charges in the Kincade Amended Complaint. A preliminary hearing on the charges began on February 8, 2022.

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On December 2, 2021, the CPUC approved a settlement between the Safety Enforcement Division and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that (i) the Utility will pay $40 million to California’s General Fund; (ii) the Utility will remove permanently abandoned transmission lines over a ten-year period; and (iii) the Utility must incur $85 million of the costs of such work by December 31, 2024, and it may not seek recovery of this $85 million of costs. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In connection with the Kincade SED Settlement, PG&E Corporation and the Utility recorded a liability of $40 million reflected in Other current liabilities on the Consolidated Financial Statements for the period ended December 31, 2021. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility expects to record such disallowances in 2022. On January 10, 2022, TURN filed an application for rehearing of the Kincade SED Settlement. On January 25, 2022, the Utility filed an opposition to the application for rehearing.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 2,605 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. In addition, on January 5, 2022, Cal Fire filed a complaint in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. Following a November 5, 2021 hearing, the San Francisco County Superior Court set a trial date of November 7, 2022.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 liability in the aggregate amount of $625 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of PG&E Corporation’s and the Utility’s Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain subrogation entities, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance).

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	625
Payments	—
Balance at December 31, 2020	625
Accrued Losses	175
Payments	(31)
Balance at December 31, 2021	$	769

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million.

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2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, 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. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office filed the Zogg Complaint charging the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges in the Zogg Complaint. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts contained in the Zogg Complaint. A hearing on the demurrer is set for April 4, 2022.

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.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 21 complaints on behalf of at least 382 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. At an October 4, 2021 hearing, the San Francisco County Superior Court set a trial date of February 6, 2023. In addition, PG&E Corporation and the Utility have been contacted by Cal Fire to accept service of a complaint filed against them for fire suppression costs incurred in connection with the 2020 Zogg fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of the Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain agencies, subrogation entities, and individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2020 Zogg fire in the amount of $100 million, for an aggregate liability of $375 million (before available insurance). Following continued negotiations during the quarter ended December 31, 2021, PG&E Corporation and the Utility entered agreements with all but one of the insurance subrogation plaintiffs in the 2020 Zogg fire litigation to resolve their claims arising from the 2020 Zogg fire.

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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.

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The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	275
Payments	—
Balance at December 31, 2020	275
Accrued Losses	100
Payments	(164)
Balance at December 31, 2021	$	211

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. As of December 31, 2021, the Utility has recorded an insurance receivable for $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $22 million in legal fees incurred. Recovery under the Utility’s insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount.

2021 Dixie Fire

According to Cal Fire, on July 13, 2021, at approximately 5:15 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service territory of the Utility. According to a Cal Fire incident update, dated October 25, 2021, 7:46 a.m. Pacific Time, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,329 structures destroyed (including 717 residential, 143 commercial, and 443 other structures), 95 structures damaged, and one fatality, which according to published reports was a fire fighter who passed away due to COVID-19 after returning home from the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility.

The Butte County, Plumas County, Shasta County, Lassen County and Tehama County District Attorneys’ Offices, as well as the SED and OEIS, are investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. 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 2021 Dixie fire. This investigation is ongoing, 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.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 20 complaints on behalf of at least 1,005 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion for the year ended December 31, 2021 (before available recoveries).

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

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As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable due to the incomplete information available to PG&E Corporation and the Utility as of the date of this filing as to facts pertinent to potential claims and defenses. Moreover, PG&E Corporation and the Utility are currently unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the National Interagency Coordination Center Incident Management Situation Report dated October 29, 2021 at 7:30 a.m. Mountain Time, over $630 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility currently estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The Utility has liability insurance coverage for third-party liability attributable to periods in which both the 2020 Zogg fire and 2021 Dixie fire occurred in an aggregate amount of $900 million. Recovery under the Utility’s insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount. An immaterial decrease was recorded in the fourth quarter of 2021. As of December 31, 2021, the Utility has recorded an insurance receivable of $563 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $337 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2021, the Utility has recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire. See “Wildfire Fund under AB 1054” below. The Utility has also recorded a $101 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $347 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. An immaterial increase was recorded in the fourth quarter of 2021.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. 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.

Total probable recoveries for the 2021 Dixie fire as of December 31, 2021 are:

Potential Recovery Source (in millions)	2021 Dixie fire
Insurance	$	563
FERC TO rates	101
WEMA	347
Wildfire Fund	150
Probable recoveries at December 31, 2021	$	1,161

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described herein, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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Insurance

Insurance Coverage

In April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period from April 13, 2021 to April 1, 2022, and approximately $32 million in incremental wildfire liability reinsurance for the period from April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire liability reinsurance for the period from July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period from August 1, 2020 to August 1, 2021. On August 1, 2021, the $600 million of existing wildfire liability coverage renewed on a 12-month term covering the period from August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In June 2021, the Utility purchased approximately $535 million in non-wildfire liability coverage for the period from June 1, 2021 to April 1, 2022 at a cost of approximately $89 million. This coverage is in addition to approximately $140 million in existing non-wildfire liability insurance for the period from August 1, 2020 to August 1, 2021. In connection with the June 2021 renewal, the Utility procured an extension of this existing coverage to April 1, 2022 at a premium cost of approximately $30 million. The Utility also has $50 million in additional non-wildfire liability coverage available through one of its wildfire liability policies with shared limits. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million. As of December 31, 2021, PG&E Corporation and the Utility had prepaid insurance of $358 million, reflected in Other current assets on the Consolidated Balance Sheets.

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.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2021, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, and $563 million for probable insurance recoveries in connection with the 2021 Dixie fire. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

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

Insurance Receivable (in millions)	2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	—	$	—	$	1,380	$	808	$	50	$	2,238
Accrued insurance recoveries	—		219		430		—		—		—		649
Reimbursements	—		—		—		(1,380)		(783)		(50)		(2,213)
Balance at December 31, 2020	—		219		430		—		25		—		674
Accrued insurance recoveries (1)	563		118		—		—		—		—		681
Reimbursements (2)	—		(67)		(16)		—		(25)		—		(108)
Balance at December 31, 2021	$	563	$	270	$	414	$	—	$	—	$	—	$	1,247

(1) During the fourth quarter of 2021, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase for the 2020 Zogg fire for $6.5 million.

(2) On January 26, 2022, the Utility received $43 million of insurance reimbursements related to the 2020 Zogg fire.

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Regulatory Recovery

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through the FERC TO formula rate in future rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire, for the year ended December 31, 2021, the Utility recorded a $101 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

In June 2018, the CPUC approved the establishment of the WEMA, which provides for tracking of incremental wildfire claims and outside legal costs plus incremental insurance premium costs above what is being recovered through rates. For the year ended December 31, 2021, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire were determined to be probable of recovery and the Utility recorded a $347 million regulatory asset in the WEMA.

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. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. 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 Coverage 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. The accrued Wildfire Fund receivable as of December 31, 2021 reflects an expectation that the Coverage Year will be based on the calendar year with coverage limited to the 2021 Dixie Fire. For 2022, PG&E Corporation and the Utility have elected a Coverage Year that commences on January 1, 2022 at 12:01 a.m. Pacific Time and ends on December 31, 2022 at 12:00 a.m. Pacific Time.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery applying the prudency standard in AB 1054, not to be just and reasonable, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $2.9 billion based on its 2021 equity rate base, and is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar year period. 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 in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund. The Utility expects that the same prudency standard would also be applied in any CPUC review of an application filed by the Utility seeking recovery of costs recorded to the WEMA.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to 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. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 14, 2021, the OEIS (then the Wildfire Safety Division of the CPUC) approved the Utility’s 2020 application and issued the Utility’s 2020 safety certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On January 31, 2022, the OEIS approved the Utility’s 2021 application and issued the Utility’s 2021 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 customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. For more information see “Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 3 above.

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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. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed 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.

As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

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 then-current and former members of the boards of directors and certain then-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 denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). 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 related to the 2017 Northern California wildfires 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 the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan. 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 or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action. The assignment became effective as of the Emergence Date. On November 12, 2020, the trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter, to which the parties later stipulated. On March 8, 2021, the court granted the parties’ stipulation to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter 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 then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff 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. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility is a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint. On November 8, 2021, the Court entered an order sustaining in part and overruling in part the demurrers. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint. Trial is set for June 27, 2022.

On January 25, 2019, a separate 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 then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A stipulation and proposed order to voluntarily dismiss this action was filed on April 20, 2021 and a case management conference on the dismissal order is set for March 9, 2022.

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The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these 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 or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.

Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California (the “District Court”), naming PG&E Corporation and certain of its then-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 Exchange Act 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, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, 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 then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

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 former 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 under submission with the District Court. The securities actions have been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with any such claims submitted through a proof of claim to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases. On April 29, 2021, the District Court issued a notice of intent to stay this action pending completion of the claims procedures in the bankruptcy proceedings. PERA filed objections to the notice of intent to stay on May 28, 2021. PG&E Corporation and the Utility filed a response to PERA’s objections on June 10, 2021, the officer, director, and underwriter defendants filed a response to PERA’s objections on June 11, 2021, and PERA filed a sur-response on June 21, 2021. The District Court has not taken further action with respect to its notice of intent to stay.

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Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility relating to, among others, 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. 18-03509, 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 separate 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, which comprises two separate classes under the Plan, 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 with respect to 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 any such allowed 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, 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 Emergence 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 Emergence 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, 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 financial condition, results of operations, liquidity, 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 Emergence 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. PERA has filed two motions seeking approval from the Bankruptcy Court to treat its proof of claim as a class claim. On February 27, 2020 and January 26, 2021, the Bankruptcy Court issued orders denying the motions. PERA filed an appeal of the February 27, 2020 order and on March 8, 2021, the District Court issued an order dismissing the appeal.

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 August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the Ninth Circuit Court of Appeals and on December 15, 2021, PERA filed its opening brief. PERA’s appeal to the Ninth Circuit remains pending.

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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 help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have been working to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by requesting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Based on discussions with certain holders of the HoldCo Rescission or Damage Claims, PG&E Corporation believes it is probable that it will incur a loss in connection with the HoldCo Rescission or Damage Claims. As of the date of this filing, PG&E Corporation determined that the amount or range of such loss is not reasonably estimable because either a negotiated resolution would be contingent upon available insurance coverage, the scope of which has not yet been agreed, or any negotiated resolutions would be limited to a subset of immaterial claims. PG&E Corporation is further unable to estimate the amount or range of loss because the nature and value of HoldCo Rescission or Damage Claims varies significantly among potential claimholders, and as of the date of this filing, PG&E Corporation has only engaged in substantive discussions with a limited subset of claimholders.

PG&E Corporation and the Utility continue to believe it is reasonably possible that they will incur a loss in connection with the Subordinated Debt Claims but are unable to reasonably estimate the amount or range of loss because the nature and value, if any, of such claims varies significantly among potential claimholders. As of December 31, 2021, PG&E Corporation and the Utility have not recorded a liability in connection with the Subordinated Claims.

De-energization Securities 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 then-current director and certain then-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 PSPS events, 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 Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a current officer of PG&E Corporation as defendants, and removed claims against certain current and former officers of PG&E Corporation previously named in the action.

On February 16, 2021, the plaintiffs filed a motion with the District Court for preliminary approval of a proposed settlement. On November 2, 2021, the District Court entered an order granting final approval of the settlement, which is now effective. Pursuant to the settlement stipulation: (1) PG&E Corporation paid $10 million, and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) released the Released Persons (as defined in the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulation of settlement.

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Indemnification Obligations and Directors’ and Officers’ Insurance Coverage

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 certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” 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 litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with the carriers regarding, among other things, the applicability of multiple years of directors’ and officers’ insurance policies to those matters. Recovery under the directors’ and officers’ insurance policies in one such litigation matter will impact the directors’ and officers’ insurance proceeds available in the other matters.

On March 17, 2021, the trustee for the Fire Victim Trust filed a lawsuit entitled Trotter v. PG&E Corporation, et al., in San Francisco Superior Court, seeking, among other things, a declaration that the trustee for the Fire Victim Trust be permitted to participate in the arbitration with the carriers. The trustee named PG&E Corporation, the Utility, and the insurance carriers as defendants. On March 25, 2021, PG&E Corporation and the Utility removed the action to the Bankruptcy Court. On March 29, 2021, the Fire Victim Trust filed a motion to remand the lawsuit back to state court, which the Bankruptcy Court denied on April 20, 2021. On April 30, 2021, the Fire Victim Trust moved for summary judgment. Oppositions and cross-motions to the summary judgment motion were filed by PG&E Corporation, the Utility and the insurance carriers on May 21, 2021. On June 22, 2021, the Bankruptcy Court entered an order denying the Fire Victim Trust’s motion for summary judgment and granting the defendants’ cross-motions for summary judgment. On June 29, 2021, the Bankruptcy Court entered judgment in favor of all defendants and against the Fire Victim Trust.

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, among other things.

The extent of PG&E Corporation’s and the Utility’s recovery of the directors’ and officers’ insurance proceeds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

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.

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 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 pleaded 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).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Court continued the hearing to February 25, 2022.

Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) 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 has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.40 billion in cash that was contributed on the Emergence Date, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million that was paid in cash on January 18, 2022, in each case pursuant to the terms of the tax benefits payment agreement between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Emergence Date, subject to potential adjustments.

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NOTE 15: 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 and the Utility 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 and the Utility have financial commitments described in “Other 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 had the ability to impose additional probation conditions on the Utility. On January 25, 2022, the period of probation expired.

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, Commission General Orders 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 the Coalition of California Utility Employees jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. The settlement agreement became effective on the Emergence Date.

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 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 recorded $1.625 billion of the disallowed costs for the year ended December 31, 2020.

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(in millions)
Description (1)	Expense		Capital		Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)	$	236	$	—	$	236
Transmission Safety Inspections and Repairs Expense (TO) (2)	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)	—		84		84
Total	$	1,222	$	403	$	1,625

(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.

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

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 and the amount of disallowance can be reasonably estimated.

The Utility expects additional system enhancement spending pursuant to the settlement agreement to 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 (iv) limits the tax savings that must be returned to customers 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. The CPUC approved the decision different on May 7, 2020.

As it relates to the additional $198 million in disallowed costs as adopted in the decision different, the Utility has recorded the full amount, primarily in the WMPMA through December 31, 2021.

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, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, 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. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are currently being held in abeyance until the FERC addresses the ROE issue.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2021 by approximately $324 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility has recorded approximately $197 million to Regulatory assets.

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On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the 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 the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

2018 CEMA Interim Rate Relief Subject to Refund

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented commencing on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund.

On November 2, 2021, the Utility filed a settlement agreement with the active parties in the matter. The settlement agreement, if approved by the CPUC, would authorize the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount has already been collected in interim rates. The interim rates would become final and no longer subject to refund. The remainder of the authorized revenue requirement that has yet to be collected would be amortized over a 12-month period.

2020 WMCE Interim Rate Relief Subject to Refund

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 “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California wildfires and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

As previously disclosed, on October 23, 2020, the CPUC approved $447 million in interim rate relief (which includes interest) pertaining to costs addressed in the 2020 WMCE application. All of the costs presented in the 2020 WMCE application are subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.

The costs addressed in the 2020 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’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility filed a motion with the CPUC seeking approval of a settlement agreement that would authorize the Utility to continue to recover an interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this hearing to April 1, 2022.

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2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit

In its final decision 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 recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit.

On July 31, 2020, the Utility filed an application seeking recovery of $416.3 million in 2015 to 2022 revenue associated with $512 million of recorded capital expenditures. On July 7, 2021, the Utility filed a joint motion to adopt a settlement agreement reached with the active parties in the proceeding. If approved by the CPUC, the settlement agreement would resolve all issues in this proceeding and would authorize a $356.3 million revenue requirement for the period of 2015 through 2022. Of this amount, $313.3 million of revenues for the period 2015 through 2021 would be amortized in rates over 60 months and $43 million associated with 2022 would be amortized in rates over 12 months through an annual gas true-up filing for rates effective January 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application would be included in test year 2023 rate base in the Utility’s consolidated 2023 GRC. No party submitted comments on the settlement.

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

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 $77 million and $144 million as of December 31, 2021 and December 31, 2020, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. 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. On March 30, 2020, the Bankruptcy Court granted the Utility’s motion to dismiss this class action because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. The appellant filed its opening brief on June 25, 2021. A former executive director of the CPUC filed an amicus brief on July 2, 2021, asking the Ninth Circuit Court of Appeals to reverse the decision of the District Court and to remand the case for further proceedings. The answering brief of PG&E Corporation and the Utility was filed August 25, 2021. On September 1, 2021, the CPUC filed an amicus brief asking the Ninth Circuit Court of Appeals to affirm the District Court’s dismissal. The appellant’s reply brief was filed on October 15, 2021. A panel of the Ninth Circuit Court of Appeals heard oral argument on the plaintiff’s appeal on January 12, 2022.

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

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CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement.

Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded a charge during the fourth quarter ended December 31, 2021 for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2021		December 31, 2020
Topock natural gas compressor station	$	299	$	303
Hinkley natural gas compressor station	123		132
Former MGP sites owned by the Utility or third parties (1)	667		659
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites (2)	104		111
Fossil fuel-fired generation facilities and sites (3)	70		96
Total environmental remediation liability	$	1,263	$	1,301

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, 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 MGP 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 as of December 31, 2021, 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. As of December 31, 2021, the Utility expected to recover $982 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

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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 $220 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 through 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 2022. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 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 $477 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 through 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 $50 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 through 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 $43 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.

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Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages. Additional coverage is procured through EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.

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 $42 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.6 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.6 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

Diablo Canyon Outages

Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator occurred during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. During July 2020 through April 2021, the Utility implemented effective corrective actions. The Utility continues to monitor the affected component.

If additional shutdowns occur in the future, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC in the 2021 Energy Resource Recovery Account compliance proceeding.

PG&E Corporation and the Utility do not currently believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

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Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2021:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2022	$	2,062	$	530	$	61	$	823	$	42	$	3,518
2023	2,043		425		61		191		41		2,761
2024	2,020		282		61		157		27		2,547
2025	2,009		216		61		157		—		2,443
2026	1,948		204		21		140		—		2,313
Thereafter	19,310		539		19		52		—		19,920
Total purchase commitments	$	29,392	$	2,196	$	284	$	1,520	$	110	$	33,502

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  As of December 31, 2021, renewable energy contracts expire at various dates between 2022 and 2041.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2022 and 2041.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2021, QF contracts in operation expire at various dates between 2022 and 2041.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity amounted to $3.0 billion in 2021, $2.9 billion in 2020, and $3.0 billion in 2019.

Natural Gas Supply, Transportation, and Storage Commitments 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2022 and 2041.  In addition, the Utility has contracted for natural gas storage services in Northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $1.2 billion in 2021, $0.8 billion in 2020, and $0.9 billion in 2019.

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Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2022 and 2024 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. 

Payments for nuclear fuel amounted to $79 million in 2021, $111 million in 2020, and $74 million in 2019.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2022 and 2052.  At December 31, 2021, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2022	$	43
2023	65
2024	81
2025	77
2026	74
Thereafter	2,938
Total minimum lease payments	$	3,278

Payments for other commitments amounted to $50 million in 2021, $45 million in 2020, and $48 million in 2019.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

Oakland Headquarters Lease

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly-owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.

The term of the Lease will begin on or about April 8, 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 requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants 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.

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 expects to 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.

At December 31, 2021, the Lease had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of PG&E Corporation and the Utility is responsible for establishing and maintaining adequate internal control over financial reporting.  PG&E Corporation’s and the Utility’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP.  Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2021, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2021.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of PG&E Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, equity and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 10, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Regulation and Regulated Operations—Refer to Notes 3, 4 and 14 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company, follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utilities Commission (“CPUC”) or the Federal Energy Regulatory Commission based on its cost of providing service. Pacific Gas & Electric Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. Pacific Gas & Electric Company capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.

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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a high degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset under GAAP and are recorded at the appropriate amount.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators and the costs approved by a CPUC decision for tracking purposes that meet the definition of a regulatory asset and are recorded at the appropriate amount included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.

•We read relevant regulatory orders issued by the CPUC for Pacific Gas and Electric Company and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•For regulatory matters in process (e.g., applications for cost recovery), we inspected Pacific Gas and Electric Company’s filings with the CPUC and the filings with the CPUC by intervenors that may affected Pacific Gas and Electric Company’s future rates, for any evidence that might contradict management’s assertions.

•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.

•We evaluated whether the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Company has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire and 2021 Dixie fire. The Company has recorded an estimated probable loss of $2,325 million as of December 31, 2021, which represents the lower end of the range of reasonably possible losses in connection with the fires.

We identified wildfire-related contingencies and the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses and (2) the outcome of the wildfire-related contingencies materially affects the Company’s financial position, results of operations, and cash flows. This required the application of a high degree of auditor judgment and extensive audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses and disclosure related to wildfire-related contingencies.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies and related disclosures included the following, among others:

•We tested the effectiveness of controls over (1) the Company’s determination of whether a loss was probable or reasonably possible; (2) the determination of the significant assumptions, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may affect the valuation of the liability; and (3) the disclosures related to the wildfires.

•We evaluated management’s judgments related to whether a loss was probable or reasonably possible for the wildfires by inquiring of management and the Company’s legal counsel regarding the amounts of probable and reasonably possible losses, including the potential impact of information gained through investigations into the cause of the fires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness of the data sources utilized to determine the assumption utilized in management’s estimate.

•We read the legal letters from the Company’s external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

Sale of Transmission Tower Wireless Licenses Agreement—Refer to Notes 3 and 4 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company, granted an exclusive license to a third party to sublicense and market wireless communications equipment attachment locations on the Utility’s structures and to add additional cell sites to the license. The Utility received $947 million in proceeds, and recorded $370 million as a financing obligation, $106 million as a contract liability (deferred revenue), and $471 million as regulatory liabilities.

We identified the accounting for the sale of the wireless licenses as a critical audit matter due to the significant judgments made by management in the application of accounting guidance. This required specialized knowledge of accounting for the sale of future revenue and leases as well as rate regulation due to its inherent complexities and extensive audit effort when performing audit procedures to evaluate the accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the Sale of Transmission Tower Wireless Licenses Agreement included the following:

•We tested the effectiveness of controls over the evaluation of the accounting treatment for the Sale of Transmission Tower Wireless Licenses Agreement.

•With the assistance of professionals in our firm having expertise in accounting for the sale of future revenue and leases, we evaluated the conclusions regarding the sale of future revenue, deferred revenue and regulatory liability accounting treatment applied to the Sale of Transmission Tower Wireless Licenses Agreement by performing the following:

◦Reading the contract terms and conditions included in the agreements

◦We read the Company’s analysis of the appropriate accounting guidance

◦Evaluating the conclusions regarding the accounting guidance used to account for the transaction

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•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

We have served as the Company’s auditor since 1999.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Pacific Gas and Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Pacific Gas and Electric Company and subsidiaries (the "Utility") as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Utility as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Utility's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 10, 2022, expressed an unqualified opinion on the Utility's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Utility's management. Our responsibility is to express an opinion on the Utility's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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Regulation and Regulated Operations – Refer to Notes 3, 4 and 14 to the financial statements

Critical Audit Matter Description

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utilities Commission (“CPUC”) or the Federal Energy Regulatory Commission based on its cost of providing service. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a high degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset under GAAP and are recorded at the appropriate amount.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators and the costs approved by a CPUC decision for tracking purposes that meet the definition of a regulatory asset and are recorded at the appropriate amount included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.

•We read relevant regulatory orders issued by the CPUC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•For regulatory matters in process (e.g., applications for cost recovery), we inspected the Utility’s filings with the CPUC and the filings with the CPUC by intervenors that may affect the Utility’s future rates, for any evidence that might contradict management’s assertions.

•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.

•We evaluated whether the Utility’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire and 2021 Dixie fire. The Utility has recorded an estimated probable loss of $2,325 million as of December 31, 2021, which represents the lower end of the range of reasonably possible losses in connection with the fires.

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We identified wildfire-related contingencies and the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses and (2) the outcome of the wildfire-related contingencies materially affects the Utility’s financial position, results of operations, and cash flows. This required the application of a high degree of auditor judgment and extensive audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses and disclosure related to wildfire-related contingencies.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies and related disclosures included the following, among others:

•We tested the effectiveness of controls over (1) the Utility’s determination of whether a loss was probable or reasonably possible; (2) the determination of the significant assumptions, including the information gained through investigations into the cause of the fires, information from claimants, and the advice of legal counsel that may affect the valuation of the liability; and (3) the disclosures related to the wildfires.

•We evaluated management’s judgments related to whether a loss was probable or reasonably possible for the wildfires by inquiring of management and the Utility’s legal counsel regarding the amounts of probable and reasonably possible losses, including the potential impact of information gained through investigations into the cause of the fire, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness the data sources utilized to determine the assumption utilized in management’s estimate.

•We read the legal letters from the Utility’s external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

•We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.

Sale of Transmission Tower Wireless Licenses Agreement—Refer to Notes 3 and 4 to the financial statements

Critical Audit Matter Description

The Utility has granted an exclusive license to a third party to sublicense and market wireless communications equipment attachment locations on the Utility’s structures and add additional cell sites to the license. The Utility received $947 million in proceeds, and recorded $370 million as a financing obligation, $106 million as a contract liability (deferred revenue), and $471 million as regulatory liabilities.

We identified the accounting for the sale of the wireless licenses as a critical audit matter due to the significant judgments made by management in the application of accounting guidance. This required specialized knowledge of accounting for the sale of future revenue and leases as well as rate regulation due to its inherent complexities and extensive audit effort when performing audit procedures to evaluate the accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the Sale of Transmission Tower Wireless Licenses Agreement included the following:

•We tested the effectiveness of controls over the evaluation of the accounting treatment for the Sale of Transmission Tower Wireless Licenses Agreement.

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•With the assistance of professionals in our firm having expertise in accounting for the sale of future revenue and leases, we evaluated the conclusions regarding the sale of future revenue, deferred revenue and regulatory liability accounting treatment applied to the Sale of Transmission Tower Wireless Licenses Agreement by performing the following:

◦Reading the contract terms and conditions included in the agreements

◦Evaluating the conclusions regarding the accounting guidance used to account for the transaction

•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

We have served as the Utility’s auditor since 1999.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of PG&E Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our report dated February 10, 2022, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

190

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Pacific Gas and Electric Company

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Utility and our report dated February 10, 2022, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Utility’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Utility’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

191

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCE DISCLOSURE

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 31, 2021, 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 1934 Act 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.

Management’s Annual Report on Internal Control over Financial Reporting

Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting.  Management’s report, together with the report of the independent registered public accounting firm, appears in Item 8 of this 2021 Form 10-K under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”

Registered Public Accounting Firm’s Report on Internal Control over Financial Reporting

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

192

PART III 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding executive officers of PG&E Corporation and the Utility is set forth under “Information About Our Executive Officers” at the end of Part I of this 2021 Form 10-K.  Other information regarding directors will be included under the heading “Election of Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference.  Information regarding compliance with Section 16 of the Exchange Act will be included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference.

Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on the Corporate Governance section of PG&E Corporation’s website (www.pgecorp.com/corp/about-us/corporate-governance.page) and on the Utility’s website (www.pge.com/en_US/about-pge/company-information/company-information.page, under the Corporate Governance and the Compliance & Ethics tabs): (1) PG&E Corporation’s and the Utility’s code of conduct (which meets the definition of “code of ethics” of Item 406(b) of the SEC Regulation S-K) adopted by PG&E Corporation and the Utility and applicable to their directors and employees, including their respective principal executive officers, principal financial officers, controllers, and other executive officers, (2) PG&E Corporation’s and the Utility’s respective corporate governance guidelines, and (3) key Board committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Sustainability and Governance Committee and the People and Compensation Committee.

If any amendments are made to, or any waivers are granted with respect to, provisions of the “code of ethics” by PG&E Corporation or the Utility and that apply to its respective principal executive officers, principal financial officers, or controllers, PG&E Corporation or the Utility, as appropriate, will post the amended code of ethics and any waivers at www.pgecorp.com/corp/about-us/compliance-ethics/program.page.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

There were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial experts” as defined by the SEC will be included under the heading “Committees and Memberships” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference. 

ITEM 11. EXECUTIVE COMPENSATION

Information responding to Item 11, for each of PG&E Corporation and the Utility, will be included under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2021,” “Grants of Plan-Based Awards in 2021,” “Outstanding Equity Awards at Fiscal Year End - 2021,” “Option Exercises and Stock Vested during 2021,” “Pension Benefits - 2021,” “Non-Qualified Deferred Compensation - 2021,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability,” “Compensation of Non-Employee Directors,” and “Principal Executive Officers’ (PEO) Pay Ratio - 2021” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility is set forth under the headings “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference.

193

Equity Compensation Plan Information

The following table provides information as of December 31, 2021 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation’s existing equity compensation plans.

	(a)		(b)			(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by shareholders	31,167,681	(1)	$	40.05	(2)	58,552,721	(3)
Equity compensation plans not approved by shareholders	—		—			—
Total equity compensation plans	31,167,681	(1)	$	40.05	(2)	58,552,721	(3)

(1) Includes 160 phantom stock units, 9,658,300 restricted stock units and 19,313,387 performance shares.  The weighted average exercise price reported in column (b) does not take these awards into account. For performance shares, amounts reflected in this table assume payout in shares at 200% of target or, for performance shares granted in 2021, reflects the estimated payout percentage of zero percent for performance shares using a total shareholder return and financial metric, 200% for performance shares using operational metrics. The actual number of shares issued can range from zero percent to 200% of target depending on achievement of performance objectives. For performance-based stock options, amounts reflected in this table reflect actual payout of 102%. Restricted stock units and performance shares are generally settled in net shares. Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, taxes will be paid on behalf of employees. Shares not issued due to share withholding or performance achievement below maximum will be available again for issuance.

(2) This is the weighted average exercise price for the 2,195,834 options outstanding as of December 31, 2021.

(3) Represents the total number of shares available for issuance under all PG&E Corporation’s equity compensation plans as of December 31, 2021. Stock-based awards granted under these plans include restricted stock units, performance shares, stock options, and phantom stock units. The LTIP, which became effective on May 12, 2014, authorizes up to 17 million shares to be issued pursuant to awards granted under the LTIP. In addition, 5.5 million shares related to awards outstanding under the 2006 long-term incentive plan at December 31, 2013, or awards granted under the 2006 long-term incentive plan from January 1, 2014, through May 11, 2014, were cancelled, forfeited or expired and became available for issuance under the LTIP. A further 30 million shares were authorized for issuance under the LTIP on July 1, 2020, as part of the Plan. Lastly, an additional 44 million shares were authorized for issuance under the new 2021 LTIP plan on June 1, 2021.

For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information responding to Item 13, for each of PG&E Corporation and the Utility, will be included under the headings “Related Party Transactions,” “Independence,” and “Committees and Memberships” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information responding to Item 14, for each of PG&E Corporation and the Utility, will be included under the heading “Information Regarding the Independent Auditor for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2022 Annual Meetings of Shareholders, which information is incorporated herein by reference.

194

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a.    The following documents are filed as a part of this report:

1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are filed as part of this report in Item 8:

Consolidated Statements of Income for the Years Ended December 31, 2021, 2020, and 2019 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2021, 2020, and 2019 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, 2021 and 2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2021, 2020, and 2019 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2021, 2020, and 2019 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Management’s Report on Internal Controls. 

Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

2.The following financial statement schedules are filed as part of this report:

Condensed Financial Information of Parent as of December 31, 2021 and 2020 and for the Years Ended December 31, 2021, 2020, and 2019.

Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2021, 2020, and 2019.

3.Exhibits required by Item 601 of Regulation S-K

Exhibit Number	Exhibit Description
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	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)
3.3	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)
3.4	Bylaws of Pacific Gas and Electric Company, Amended and Restated as of May 20, 2021 (incorporated by reference in Pacific Gas and Electric Company’s Form 10-Q dated May 20, 2021 (File No. 1-2348), Exhibit 3.1)
3.5	Amended and Restated Limited Liability Company Agreement of PG&E Recovery Funding LLC, dated as of October 27, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 4, 2021 (File No. 1-2348), Exhibit 3.2)

195

4.1	Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture, dated as of August 6, 2018, relating to the issuance by Pacific Gas and Electric Company of $500,000,000 aggregate principal amount of 4.25% Senior Notes due August 1, 2023 and $300,000,000 aggregate principal amount of 4.65% Senior Notes due August 1, 2028 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.2)
4.3	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)
4.4	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2005 (File No. 1-2348), Exhibit 4.1)
4.5	First Supplemental Indenture, dated as of March 13, 2007, relating to the issuance of $700,000,000 principal amount of Pacific Gas and Electric Company’s 5.80% Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.6	Third Supplemental Indenture, dated as of March 3, 2008, relating to the issuance of $400,000,000 of Pacific Gas and Electric Company’s 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)
4.7	Sixth Supplemental Indenture, dated as of March 6, 2009, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
4.8	Eighth Supplemental Indenture, dated as of November 18, 2009, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
4.9	Ninth Supplemental Indenture, dated as of April 1, 2010, relating to the issuance of $250,000,000 aggregate principal amount of its 5.80% Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
4.10	Ninth Supplemental Indenture, dated as of June 3, 2021, relating to the $800,000,000 aggregate principal amount of 3.000% First Mortgage Bonds due June 15, 2028 (the “First Mortgage Bonds”), between Pacific Gas and Electric Company and the Trustee (including the form of First Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 1-2348), Exhibit 4.1)
4.11	Twelfth Supplemental Indenture, dated as of November 18, 2010, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of its 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)
4.12	Thirteenth Supplemental Indenture, dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)
4.13	Fourteenth Supplemental Indenture, dated as of September 12, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)

196

4.14	Sixteenth Supplemental Indenture, dated as of December 1, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
4.15	Seventeenth Supplemental Indenture, dated as of April 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.16	Eighteenth Supplemental Indenture, dated as of August 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of its 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
4.17	Nineteenth Supplemental Indenture, dated as of June 14, 2013, relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
4.18	Twentieth Supplemental Indenture, dated as of November 12, 2013, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)
4.19	Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No. 1-2348), Exhibit 4.1)
4.20	Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 1-2348), Exhibit 4.1)
4.21	Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 1-2348), Exhibit 4.1)
4.22	Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)
4.23	Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015, relating to the issuance of $200,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $450,000,000 aggregate principal amount of its 4.25% Senior Notes due March 15, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 5, 2015 (File No. 1-2348), Exhibit 4.1)
4.24	Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.95% Senior Notes due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 1, 2016 (File No. 1-2348), Exhibit 4.1)
4.25	Twenty-Eighth Supplemental Indenture, dated as of December 1, 2016, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 30, 2017 and $400,000,000 aggregate principal amount of its 4.00% Senior Notes due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2016 (File No. 1-2348), Exhibit 4.1)

197

4.26	Twenty-Ninth Supplemental Indenture, dated as of March 10, 2017, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.30% Senior Notes due March 15, 2027 and $200,000,000 aggregate principal amount of its 4.00% Senior Notes due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 10, 2017 (File No. 1-2348), Exhibit 4.1)
4.27	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 as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.3)
4.28	Indenture, dated as of November 29, 2017, relating to the issuance of $500,000,000 aggregate principal amount of by Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 28, 2018, $1,150,000,000 aggregate principal amount of its 3.30% Senior Notes due December 1, 2027 and $850,000,000 aggregate principal amount of its 3.95% Senior Notes due December 1, 2047 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 29, 2017 (File No. 1-2348), Exhibit 4.1)
4.29	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 as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.4)
4.30	Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National Association (incorporated by reference to PG&E Corporation’s Form S-3 dated February 11, 2014 (File No. 333-193880), Exhibit 4.1)
4.31	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)
4.32	First Supplemental Indenture, dated as of June 19, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the 1.75% First Mortgage Bonds due June 16, 2022, 2.10% First Mortgage Bonds due August 1, 2027, 2.50% First Mortgage Bonds due February 1, 2031, 3.30% First Mortgage Bonds due August 1, 2040 and 3.50% First Mortgage Bonds due August 1, 2050, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (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)
4.33	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 as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.6)
4.34	Third Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to 3.75% First Mortgage Bond due July 1, 2028 and 3.45% First Mortgage Bond due July 1, 2025 (collectively, the “Short-Term Exchange Mortgage Bonds”) and 4.95% First Mortgage Bond due July 1, 2050 and 4.55% First Mortgage Bond due July 1, 2030 (collectively, the “Long-Term Exchange Mortgage Bonds”) between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Short-Term Exchange Mortgage Bonds and the Long-Term Exchange Mortgage 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)
4.35	Fourth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to 3.15% First Mortgage Bond due July 1, 2026 and 4.50% First Mortgage Bond due July 1, 2040 (collectively, the “Funded Debt Mortgage Bonds”) 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 Mortgage 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)
4.36	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 collateral bonds securing the $1,500,000,000 18-month term loan facility and the $1,500,000,000 364-day term loan facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.7)

198

4.37	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 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 4.15)
4.38	Pledge Agreement, dated as of October 5, 2020, by and between Pacific Gas and Electric Company and MUFG Bank, Ltd. (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 4.1)
4.39	Eighth Supplemental Indenture, dated as of March 11, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $1,500,000,000 aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450,000,000 aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 Bonds and $450,000,000 aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041 Bonds, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A.(including the form of First Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 8, 2021 (File No. 1-2348), Exhibit 4.1)
4.40	Ninth Supplemental Indenture, dated as of June 3, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $800,000,000 aggregate principal amount of 3.000% First Mortgage Bonds due June 15, 2028 (the “2028 Bonds”), between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of 2028 Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 1-2348), Exhibit 4.1)
4.41	Tenth Supplemental Indenture, dated as of June 22, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the collateral bonds, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the forms of collateral bonds securing the revolving credit facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 4.1)
4.42	Eleventh Supplemental Indenture, dated as of October 29, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the collateral bond, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of collateral bond securing the 18-month term loan facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-2348), Exhibit 4.2)
4.43	Twelfth Supplemental Indenture, dated as of November 15, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $300,000,000 aggregate principal amount of Floating Rate Mortgage Bonds due November 14, 2022 (the “Floating Rate Mortgage Bonds”) and the $900,000,000 aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 (the “2023 Bonds”), between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the forms of Floating Rate Mortgage Bonds and 2023 Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 10, 2021 File No. 1-2348), Exhibit 4.1)
4.44	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)
4.45	First Supplemental Indenture, dated as of June 23, 2020, to the Indenture, dated as of June 23, 2020, relating to the 5.000% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and the 5.250% Senior Secured Notes due July 1, 2030 (the “2030 Notes”; together with the 2028 Notes, the “Notes”), by and among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., 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)
4.46	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 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.3)
4.47	Calculation Agency Agreement, dated as June 19, 2020, by and 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)
4.48	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 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.4)

199

4.49		Indenture, dated as of November 12, 2021, by and between PG&E Recovery Funding LLC and The Bank of New York Melon Trust Company, N.A. (including forms of the Senior Secured Recovery Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-12609), Exhibit 4.1)
4.50		Series Supplement, dated as of November 12, 2021, by and between PG&E Recovery Funding LLC and The Bank of New York Melon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-12609), Exhibit 4.2)
4.51(a)		Description of PG&E Corporation’s Securities – Common Stock and Equity Units
4.51(b)		Description of Pacific Gas and Electric Company’s Securities – Preferred Stock
10.1		Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank, National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)
10.2		Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)
10.3		Term Loan Agreement, dated as of April 16, 2018, by and among PG&E Corporation, the several banks and other financial institutions or entities from time to time parties thereto, Mizuho Bank, Ltd., Royal Bank of Canada and Sumitomo Mitsui Banking Corporation, as joint lead arrangers and joint bookrunners and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to PG&E Corporation’s Form 8-K dated April 16, 2018 (File No. 1-12609), Exhibit 10.1)
10.4		Term Loan Agreement, dated as of February 23, 2018, by and among Pacific Gas and Electric Company, the several banks and other financial institutions or entities from time to time parties thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank National Association, as joint lead arrangers and joint bookrunners and The Bank of Tokyo-Mitsubishi UFJ, Ltd, as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 23, 2018 (File No. 1-02348), Exhibit 10.1)
10.5		Transmission Control Agreement among the California Independent System Operator Corporation (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.8)
10.6	*	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)
10.7	*	Office Lease, dated as of October 23, 2020, by and between Pacific Gas and Electric Company and BA2 300 Lakeside LLC (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.12)
10.8		Calculation Agency Agreement, dated as of November 16, 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 November 16, 2020 (File No. 1-2348), Exhibit 4.2)

200

10.9	Repricing Amendment, dated February 1, 2021, by and among PG&E Corporation, the Consenting Lenders, the New Lenders (each as defined therein) and JPMorgan Chase Bank, N.A, as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.2)
10.10	Underwriting Agreement, dated March 8, 2021, by and among Pacific Gas and Electric Company, BNP Paribas Securities Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC and MUFG Securities Americas Inc. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 8, 2021 (File No. 1-2348), Exhibit 1.1)
10.11	Underwriting Agreement, dated June 1, 2021, by and among Pacific Gas and Electric Company, Barclays Capital Inc., BofA Securities, Inc., Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 1-2348), Exhibit 1.1)
10.12	Underwriting Agreement, dated November 4, 2021, by and among PG&E Recovery Funding LLC, Pacific Gas and Electric Company, Goldman Sachs & Co. LLC and Citigroup Global Markets Inc. (incorporated by reference to Pacific Gas & Electric Company’s Form 8-K dated November 4, 2021 (File No. 1-2348), Exhibit 1.1)
10.13	Underwriting Agreement, dated November 10, 2021, by and among Pacific Gas and Electric Company, Barclays Capital Inc., Citigroup Global Markets Inc., MUFG Securities Americas Inc. and Wells Fargo Securities, LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 10, 2021 (File No. 1-2348), Exhibit 1.1)
10.14	Equity Distribution Agreement, dated April 30, 2021, by and among PG&E Corporation, Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and forward sellers, and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (incorporated by reference to PG&E Corporation’s Form 8-K dated April 30, 2021 (File No. 1-12609), Exhibit 1.1)
10.15	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)
10.16	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)
10.17	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)
10.18	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)
10.19	Registration Rights Agreement, dated as of August 6, 2018, among Pacific Gas and Electric Company, Goldman Sachs & Co. LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc., as representatives of the initial purchasers (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.5)
10.20	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)
10.21	Amended and Restated Registration Rights Agreement, dated as of July 8, 2021, by and between PG&E Corporation and the PG&E Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated July 8, 2021 (File No. 1-12609), Exhibit 4.1)
10.22	Credit Agreement, dated as of July 1, 2020, by and among PG&E Corporation, the several lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and JPMorgan Chase Bank, N.A., as collateral agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.3)

201

10.23	Amendment No. 1 to Credit Agreement, dated as of June 22, 2021, by and among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time, JP Morgan Chase Bank, N.A., as administrative agent and collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 22, 2021 (File No. 1-12609), Exhibit 10.1)
10.24	Term Loan Agreement, dated June 23, 2020, by and among PG&E Corporation, 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)
10.25	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, JPMorgan Chase Bank, N.A. and Citibank, N.A., as co-administrative agents, and Citibank, N.A., as designated 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	Amendment No. 1 to Credit Agreement, dated as of June 22, 2021, by and among Pacific Gas and Electric Company, the several banks and other financial institutions or entities party thereto from time to time, JP Morgan Chase Bank, N.A., as co-administrative agents and Citibank, N.A,, as designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 10.2)
10.27	Term Loan Credit Agreement, dated as of July 1, 2020, among Pacific Gas and Electric Company, the several lenders from time to time party thereto and JPMorgan 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)
10.28	Amendment No. 1 to Credit Agreement, dated as of October 29, 2021, by and among Pacific Gas and Electric Company, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.5)
10.29	Amendment No. 2 to Credit Agreement, dated as of December 31, 2021, by and among Pacific Gas and Electric Company, the Consenting Lenders, the other Lenders (each as defined therein) and JPMorgan Chase Bank, N.A., as administrative agent
10.30	Amendment No. 3 to Credit Agreement, dated as of February 8, 2022, by and among Pacific Gas and Electric Company, the Consenting Lenders (each as defined therein) and JPMorgan Chase Bank, N.A., as administrative agent
10.31	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)
10.32	Amendment No. 1 to Purchase and Sale Agreement, dated as of January 14, 2021, 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 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.75)
10.33	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 (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.2)
10.34	Amendment No. 1 to Receivables Financing Agreement, dated as of January 14, 2021, 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 (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.77)
10.35	Amendment No. 2 to Receivables Financing Agreement, dated as of February 12, 2021, 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 (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.78)

202

10.36		Amendment No. 3 to Receivables Financing Agreement, dated as of May 5, 2021, 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 (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.2)
10.37		Amendment No. 4 to Receivables Financing Agreement, dated as of September 15, 2021, 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 (each as defined therein) incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.3)
10.38		Collection Account Intercreditor Agreement, dated as of October 5, 2020, by and among Pacific Gas and Electric Company, MUFG Bank, Ltd., 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)
10.39		PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, dated as of July 8, 2021, by and among PG&E Corporation, Pacific Gas and Electric Company, PG&E ShareCo LLC and the PG&E Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated July 8, 2021 (File No. 1-12609), Exhibit 10.1)
10.40		Recovery Property Servicing Agreement between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer, dated as of November 12, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.1)
10.41		Recovery Property Purchase and Sale Agreement between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Seller, dated as of November 12, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.2)
10.42		Administration Agreement between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as administrator, dated as of November 12, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.3)
10.43		Master Transaction Agreement, dated as of February 2, 2021, by and between Pacific Gas and Electric Company and Golden State Licensing, LLC. (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.80)
10.44		Purchase Agreement, dated as of May 21, 2021, by and between Pacific Gas and Electric Company and Hines Atlas US LP (incorporated by reference to PG&E Corporation’s Form 8-K dated May 21, 2021 (File No. 1-2609), Exhibit 10.1)
10.45		First Amendment to Purchase Agreement, dated as of September 14, 2021, by and between Pacific Gas and Electric Company and HNG Atlas US LP (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.4)
10.46		Repricing Amendment, dated February 1, 2021, by and among PG&E Corporation, the Consenting Lenders, the New Lenders (each as defined therein) and JPMorgan Chase Bank, N.A, as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quartered ended March 31, 2021 (File No. 1-12609), Exhibit 10.2)
10.47	**	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of June 3, 2019 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.9)
10.48	**	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective as of June 3, 2019 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.10)
10.49	**	PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
10.50	**	PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 15, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.3)

203

10.51	**	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2021 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 9, 2021 (File No. 1-12609)
10.52	**	Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)
10.53	**	Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)
10.54	**	Pacific Gas and Electric Company Officer Relocation Handbook, effective December 15, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.99)
10.55	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective January 1, 2019.(incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.100)
10.56	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective February 6, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2014 (File No. 1-2348), Exhibit 10.37)
10.57	**	Postretirement Life Insurance Plan of Pacific Gas and Electric Company, as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)
10.58	**	Form of Restricted Stock Unit Agreement for 2018 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12609), Exhibit 10.07)
10.59	**	Form of Restricted Stock Unit Agreement for 2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 File No. 1-12609), Exhibit 10.13)
10.60	**	Form of Stock Option Agreement for 2018 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12609), Exhibit 10.08)
10.61	**	Form of Restricted Stock Unit Agreement for 2021 grants to Non-Employee Directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2021 (File No. 1-12609), Exhibit 10.8)
10.62	**	Form of Performance Share Agreement subject to financial goals for 2018 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12609), Exhibit 10.04)
10.63	**	Form of Performance Share Agreement subject to safety goals for 2018 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12609), Exhibit 10.05)
10.64	**	Form of Performance Share Agreement subject to total shareholder return goals for 2018 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12609), Exhibit 10.06)
10.65	**	Form of Performance Share Unit Agreement subject to customer experience, public safety and financial goals for 2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q dated March 31, 2021 (File No. 1-12609), Exhibit 10.14)
10.66	**	Form of Performance Share Unit Agreement subject to total shareholder return goals for 2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.15)
10.67	**	PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted effective January 1, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3)
10.68	**	PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)

204

10.69	**	PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
10.70	**	Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)
10.71	**	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No.1-12609), Exhibit 10.24)
10.72	**	Amended and Restated PG&E Corporation Director Grantor Trust Agreement dated October 1, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.01)
10.73	**	Amended and Restated PG&E Corporation Officer Grantor Trust Agreement dated October 1, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.2)
10.74	**	PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective February 19, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.119)
10.75	**	Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
10.76	**	Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
10.77	**	Form of Director and Officer Indemnification Agreement (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.8)
10.78	**	Offer Letter between PG&E Corporation and Patricia K. Poppe, effective November 13, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated November 18, 2020 (File No. 1-12609), Exhibit 10.1)
10.79	**	Offer Letter between Pacific Gas and Electric Company and Adam L. Wright, dated January 16, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.7)
10.80	**	Offer Letter between Pacific Gas and Electric Company and Marlene M. Santos, dated January 26, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.9)
10.81	**	Offer Letter between Pacific Gas and Electric Company and Jason M. Glickman, dated March 24, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.12)
10.82	**	Offer Letter between PG&E Corporation and Ajay Waghray, dated July 29, 2020.
10.83	**	Offer Letter between Pacific Gas and Electric Company and Julius Cox, dated January 8, 2021.
10.84	**	Offer Letter between PG&E Corporation and Carla Peterman, dated April 14, 2021
10.85	**	Offer Letter between PG&E Corporation and Sumeet Singh, dated June 30, 2020
10.86	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Patricia K. Poppe, dated January 15, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q dated September 30, 2021 (File No. 1-12609), Exhibit 10.6)
10.87	**	Non-Annual Restricted Stock Unit Award Agreement between Adam L. Wright and PG&E Corporation, dated March 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609, Exhibit 10.8)
10.88	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Marlene M. Santos, dated March 15, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.10)

205

10.89	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Christopher A. Foster, dated March 22, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.11)
10.90		Restricted Stock Unit Award Agreement between PG&E Corporation and William L. Smith, dated August 3, 2020 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.31)
10.91	***	Amended and Restated Performance Share Award Agreement between PG&E Corporation and William L. Smith, dated August 3, 2020 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.127)
10.92	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Julius Cox, dated March 1, 2021
10.93	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Carla Peterman, dated June 1, 2021
10.94	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and John Simon, dated August 14, 2020 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.32)
10.95	**	PG&E Corporation 2014 Long-Term Incentive Plan (as adopted effective May 12, 2014 and as last amended effective July 1, 2020) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.40)
10.96	**	PG&E Corporation 2021 Long-Term Incentive Plan (incorporated by reference to Appendix A to PG&E Corporation’s definitive proxy statement on Schedule 14A filed on April 8, 2021)
10.97	**	Form of 2020 Performance Share Award Agreement under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.41)
10.98	**	PG&E Corporation 2012 Officer Severance Policy, as amended effective as of September 24, 2020 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.42)
10.99	**	PG&E Corporation 2012 Officer Severance Policy, as amended effective as of November 1, 2021
21		Subsidiaries of the Registrant
23.1		PG&E Corporation Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
23.2		Pacific Gas and Electric Company Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24		Powers of Attorney
31.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	***	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1	***	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
101.INS		XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

206

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*	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.
**	Management contract or compensatory plan, contract or arrangement.
***	Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

207

ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2021 to be signed on their behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.

	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
	(Registrant)		(Registrant)
	/s/ PATRICIA K. POPPE		/s/ ADAM L. WRIGHT
	Patricia K. Poppe		Adam L. Wright
By:	Chief Executive Officer	By:	Executive Vice President, Operations and Chief Operating Officer
Date:	February 10, 2022	Date:	February 10, 2022
			/s/ MARLENE M. SANTOS
			Marlene M. Santos
		By:	Executive Vice President and Chief Customer Officer
		Date:	February 10, 2022
			/s/ JASON M. GLICKMAN
			Jason M. Glickman
		By:	Executive Vice President, Engineering, Planning, and Strategy
		Date:	February 10, 2022

Signature	Title	Date
A.  Principal Executive Officers
/s/ PATRICIA K. POPPE	Chief Executive Officer	February 10, 2022
Patricia K. Poppe	(PG&E Corporation)

/s/ ADAM L. WRIGHT	Executive Vice President, Operations and Chief Operating Officer	February 10, 2022
Adam L. Wright	(Pacific Gas and Electric Company)

208

/s/ MARLENE M. SANTOS	Executive Vice President and Chief Customer Officer	February 10, 2022
Marlene M. Santos	(Pacific Gas and Electric Company)

/s/ JASON M. GLICKMAN	Executive Vice President, Engineering, Planning, and Strategy	February 10, 2022
Jason M. Glickman	(Pacific Gas and Electric Company)

B. Principal Financial Officers
/s/ CHRISTOPHER A. FOSTER	Executive Vice President and Chief Financial Officer	February 10, 2022
Christopher A. Foster	(PG&E Corporation)

/s/ DAVID S. THOMASON	Vice President, Chief Financial Officer, and	February 10, 2022
David S. Thomason	Controller (Pacific Gas and Electric Company)

C. Principal Accounting Officer
/s/ DAVID S. THOMASON	Vice President, Chief Financial Officer, and	February 10, 2022
David S. Thomason	Controller (Pacific Gas and Electric Company)

	C.  Directors (PG&E Corporation and Pacific Gas and Electric Company, unless otherwise noted)
*	/s/ RAJAT BAHRI	Director	February 10, 2022
	Rajat Bahri

*	/s/ CHERYL F. CAMPBELL	Director	February 10, 2022
	Cheryl F. Campbell

*	/s/ KERRY W. COOPER	Director	February 10, 2022
	Kerry W. Cooper

*	/s/ JESSICA L. DENECOUR	Director	February 10, 2022
	Jessica L. Denecour

*	/s/ MARK E. FERGUSON III	Director	February 10, 2022
	Mark E. Ferguson III

*	/s/ ROBERT C. FLEXON	Director	February 10, 2022
	Robert C. Flexon	Chair of the Board (PG&E Corporation)

*	/s/ W. CRAIG FUGATE	Director	February 10, 2022
	W. Craig Fugate

209

*	/s/ ARNO L. HARRIS	Director	February 10, 2022
	Arno L. Harris

*	/s/ MICHAEL R. NIGGLI	Director	February 10, 2022
	Michael R. Niggli

*	/s/ PATRICIA K. POPPE	Director	February 10, 2022
	Patricia K. Poppe

*	/s/ DEAN L. SEAVERS	Director	February 10, 2022
	Dean L. Seavers	Chair of the Board (Pacific Gas and Electric Company)

*	/s/ WILLIAM L. SMITH	Director	February 10, 2022
	William L. Smith

*	/s/ BENJAMIN F. WILSON	Director	February 10, 2022
	Benjamin F. Wilson

*	/s/ ADAM L. WRIGHT	Director (Pacific Gas and Electric Company)	February 10, 2022
	Adam L. Wright

*By:	/s/ JOHN R. SIMON	February 10, 2022
	John R. Simon, Attorney-in-Fact

210

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Years Ended December 31,
(in millions, except per share amounts)	2021		2020		2019
Administrative service revenue	$	118	$	127	$	138
Operating expenses	(124)		(103)		(114)
Interest income	—		—		1
Interest expense	(230)		(149)		(21)
Other income (expense)	(54)		13		10
Reorganization items, net	1		(1,649)		(26)
Equity in earnings of subsidiaries	137		411		(7,622)
Loss before income taxes	(152)		(1,350)		(7,634)
Income tax provision (benefit)	(64)		(46)		8
Net loss	$	(88)	$	(1,304)	$	(7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $7, and $0, at respective dates)	$	7	$	(17)	$	(1)
Total other comprehensive income (loss)	7		(17)		(1)
Comprehensive Loss	$	(81)	$	(1,321)	$	(7,643)
Weighted Average Common Shares Outstanding, Basic (1)	2,463		1,257		528
Weighted Average Common Shares Outstanding, Diluted (1)	2,463		1,257		528
Net loss per common share, basic	$	(0.05)	$	(1.05)	$	(14.50)
Net loss per common share, diluted	$	(0.05)	$	(1.05)	$	(14.50)

(1) Includes 477,743,590 shares of common stock issued to ShareCo.

211

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED BALANCE SHEETS

	Balance at December 31,
(in millions)	2021		2020
ASSETS
Current Assets
Cash and cash equivalents	$	126	$	223
Advances to affiliates	21		48
Income taxes receivable	10		12
Other current assets	12		13
Total current assets	169		296
Noncurrent Assets
Equipment	2		2
Accumulated depreciation	(2)		(2)
Net equipment	—		—
Investments in subsidiaries	30,232		25,244
Other investments	181		186
Operating lease right of use asset	—		3
Deferred income taxes	297		237
Total noncurrent assets	30,710		25,670
Total Assets	$	30,879	$	25,966
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt, classified as current	27		28
Accounts payable – other	200		49
Operating lease liabilities	—		3
Other current liabilities	69		72
Total current liabilities	296		152
Noncurrent Liabilities
Debtor-in-possession financing	4,592		4,624
Operating lease liabilities	—		—
Other noncurrent liabilities	168		191
Total noncurrent liabilities	4,760		4,815
Common Shareholders’ Equity
Common stock	35,129		30,224
Reinvested earnings	(9,286)		(9,198)
Accumulated other comprehensive loss	(20)		(27)
Total common shareholders’ equity	25,823		20,999
Total Liabilities and Shareholders’ Equity	$	30,879	$	25,966

212

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities:
Net loss	$	(88)	$	(1,304)	$	(7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	51		28		43
Equity in earnings (loss) of subsidiaries	(139)		(412)		7,622
Deferred income taxes and tax credits-net	(60)		(50)		—
Reorganization items, net (Note 2)	(32)		1,548		11
Current income taxes receivable/payable	2		—		6
Liabilities subject to compromise	—		12		28
Other	81		97		(62)
Net cash provided by (used in) operating activities	(185)		(81)		6
Cash Flows From Investing Activities:
Investment in subsidiaries	—		(12,986)		—
Net cash used in investing activities	—		(12,986)		—
Cash Flows From Financing Activities:
Debtor-in-possession credit facility debt issuance costs	—		—		(16)
Bridge facility financing fees	—		(40)		—
Proceeds from issuance of long-term debt	—		4,660		—
Repayment of long-term debt	(28)		(664)		—
Intercompany note from the Utility	145		—		—
Common stock issued	—		7,582		85
Equity Units issued	—		1,304		—
Other	(29)		—		—
Net cash provided by financing activities	88		12,842		69
Net change in cash and cash equivalents	(97)		(225)		75
Cash and cash equivalents at January 1	223		448		373
Cash and cash equivalents at December 31	$	126	$	223	$	448
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(207)	$	(105)	$	(3)
Income taxes, net	1		—		—
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets	$	—	$	—	$	9
Common stock issued in satisfaction of liabilities	—		8,276		—
Increase to PG&E Corporation common stock and treasury stock in connection     with the Share Exchange and Tax Matters Agreement	4,854		—		—

213

PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2021, 2020, and 2019

(in millions)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146
2019:
Allowance for uncollectible accounts (1)	$	56	$	—	$	—	$	13	$	43

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

214

PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2021, 2020, and 2019

(in millions)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146
2019:
Allowance for uncollectible accounts (1)	$	56	$	—	$	—	$	13	$	43

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

215

EX-4.51(A)

EXHIBIT 4.51(a)

DESCRIPTION OF PG&E CORPORATION’S SECURITIES REGISTERED UNDER SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

The following description of PG&E Corporation’s common stock (the “Common Stock”) and equity units (each an “Equity Unit”) is only a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to applicable law, our Amended and Restated Articles of Incorporation effective as of June 22, 2020 (the “Articles of Incorporation”), our Bylaws amended and restated as of June 22, 2020 (the “Bylaws”), the purchase contract agreement (the “purchase contract agreement”), dated as of July 1, 2020 between us and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent (the “purchase contract agent”) and attorney-in-fact for the holders of purchase contracts from time to time and the custodial agreement (the “custodial agreement”), dated as of July 1, 2020 between the purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as the custodian for the holders of the Equity Units (the “custodian”), each of which is filed as an exhibit to this Annual Report on Form 10-K and is incorporated by reference herein. We encourage you to read the Articles of Incorporation, the Bylaws, the purchase contract agreement and the custodial agreement for additional information.

In this section, references to “we,” “our,” “ours” and “us” refer only to PG&E Corporation and not to any of its direct or indirect subsidiaries or affiliates except as expressly provided.

Description of the Common Stock

General

Our Articles of Incorporation authorize the issuance of 3,600,000,000 shares of Common Stock and 400,000,000 shares of preferred stock. As of December 31, 2021, there were approximately 1,985,400,540 shares of our Common Stock, no par value, outstanding and no shares of preferred stock outstanding. All outstanding shares of our Common Stock are fully paid and nonassessable.

We may issue our Common Stock from time to time upon such terms and for such consideration as may be determined by our Board of Directors. Such further issuances, up to the aggregate amounts authorized by our Articles of Incorporation, will not require approval by our shareholders. We may also issue Common Stock from time to time under dividend reinvestment and employee benefit plans.

Voting Rights

Except as otherwise provided by law, holders of our Common Stock have voting rights on the basis of one vote per share on each matter submitted to a vote at a meeting of shareholders, subject to any class or series voting rights of holders of our preferred stock. Our shareholders may not cumulate votes in elections of directors. As a result, the holders of our Common Stock and (if issued) preferred stock entitled to exercise more than 50% of the voting rights in an election of directors can elect all of the directors to be elected if they choose to do so. In such event, the holders of the remaining Common Stock and preferred stock voting for the election of directors will not be able to elect any persons to the Board of Directors.

Dividend Rights

Holders of our Common Stock, subject to any prior rights or preferences of preferred stock outstanding, have equal rights to receive dividends if and when declared by our Board of Directors out of funds legally available therefor.

Liquidation Rights

In the event of our liquidation, dissolution or winding up and after payment of all prior claims, holders of our Common Stock would be entitled to receive any of our remaining assets, subject to any preferential rights of holders of outstanding shares of preferred stock.

Conversion, Redemption and Preemptive Rights

Holders of our Common Stock have no preemptive rights to subscribe for additional shares of Common Stock or any of our other securities, nor do holders of our Common Stock have any redemption or conversion rights.

Listing

Our Common Stock is listed on the New York Stock Exchange under the symbol “PCG.”

Transfer Agent and Registrar

The transfer agent and registrar for our Common Stock is EQ Shareowner Services.

Limitations on Rights of Holders of Common Stock - Preferred Stock

The rights of holders of Common Stock may be materially limited or qualified by the rights of holders of preferred stock that we may issue in the future. Set forth below is a description of PG&E Corporation’s authority to issue preferred stock and the possible terms of that stock.

Our Board of Directors is authorized, pursuant to our Articles of Incorporation, to issue up to 400,000,000 shares of preferred stock in one or more series and to fix and determine the number of shares of preferred stock of any series, to determine the designation of any such series, to increase or decrease the number of shares of any such series subsequent to the issue of shares of that series, and to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any such series.

Prior to the issuance of shares of each series of our preferred stock, our Board of Directors is required to adopt resolutions and file a certificate of determination with the Secretary of State of the State of California. The certificate of determination will fix for each series the designation and number of shares and the rights, preferences, privileges and restrictions of the shares including, but not limited to, the following:

•the title and stated value of the preferred stock;

•voting rights, if any, of the preferred stock;

•any rights and terms of redemption (including sinking fund provisions);

•the dividend rate(s), period(s) and/or payment date(s) or method(s) of calculation applicable to the preferred stock;

•whether dividends are cumulative or non-cumulative and, if cumulative, the date from which dividends on the preferred stock will accumulate;

•the relative ranking and preferences of the preferred stock as to dividend rights and rights upon the liquidation, dissolution or winding up of our affairs;

•the terms and conditions, if applicable, upon which the preferred stock will be convertible into our Common Stock, including the conversion price (or manner of calculation) and conversion period;

•the provision for redemption, if applicable, of the preferred stock;

•the provisions for a sinking fund, if any, for the preferred stock;

•liquidation preferences;

•any limitations on issuance of any class or series of preferred stock ranking senior to or on a parity with the class or series of preferred stock as to dividend rights and rights upon liquidation, dissolution or winding up of our affairs; and

•any other specific terms, preferences, rights, limitations or restrictions of the preferred stock.

All shares of preferred stock will, when issued, be fully paid and nonassessable and will not have any preemptive or similar rights.

In addition to the terms listed above, we will set forth in a prospectus supplement the following terms relating to the class or series of preferred stock being offered:

•the number of shares of preferred stock offered, the liquidation preference per share and the offering price of the preferred stock;

•the procedures for any auction and remarketing, if any, for the preferred stock;

•any listing of the preferred stock on any securities exchange; and

•a discussion of any material and/or special United States federal income tax considerations applicable to the preferred stock.

Until our Board of Directors determines the rights of the holders of a series of preferred stock, we cannot predict the effect of the issuance of any shares of such series of preferred stock upon the rights of holders of our Common Stock. However, the effect could include one or more of the following:

•restricting dividends on our Common Stock;

•diluting the voting power of our Common Stock;

•impairing the liquidation rights of our Common Stock; or

•delaying or preventing a change in control of us without further action by our shareholders.

Our preferred stock, if issued, would rank, with respect to dividends and upon our liquidation, dissolution or winding up:

•senior to all classes or series of our Common Stock and to all of our equity securities ranking junior to the preferred stock;

•on a parity with all of our equity securities the terms of which specifically provide that the equity securities rank on a parity with the preferred stock; and

•junior to all of our equity securities the terms of which specifically provide that the equity securities rank senior to the preferred stock.

Holding Company Structure

PG&E Corporation conducts its operations primarily through its subsidiaries and substantially all of its consolidated assets are held by its subsidiaries, including Pacific Gas and Electric Company (the “Utility”). Accordingly, PG&E Corporation’s cash flow and its ability to meet its obligations are largely dependent upon the earnings of its subsidiaries and the distribution or other payment of these earnings to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances. PG&E Corporation’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts or make any funds available for payment pursuant to PG&E Corporation’s obligations.

Because PG&E Corporation is a holding company, its obligations will be structurally subordinated to all existing and future liabilities of its subsidiaries, including all debt securities and issued and outstanding preferred stock of the Utility (see Exhibit 4.[51](b) for a description of such preferred stock). Furthermore, the rights of PG&E Corporation to participate in the assets of any subsidiary upon the liquidation or reorganization of the subsidiary will be subject to the prior claims of such subsidiary’s creditors, including any holders of preferred stock of such subsidiary. To the extent that PG&E Corporation is itself a creditor with recognized claims against any of its subsidiaries, its claims would still be effectively subordinated to any security interest in, or mortgages or other liens on, the assets of the subsidiary and would be subordinated to any indebtedness or other liabilities of the subsidiary that are senior to the claims held by PG&E Corporation.

Description of the Equity Units

In July and August 2020, we issued 16,000,000 Equity Units, each with a stated amount of $100. Each Equity Unit is comprised of (i) a prepaid forward stock purchase contract (a “purchase contract”) of PG&E Corporation and (ii) a

1/48,000th undivided beneficial ownership interest in specified U.S. treasury strips that mature on a quarterly basis from, and including, August 15, 2020 through, and including, August 15, 2023 and are held by the custodian as agent for the holders of the Equity Units (a “U.S. treasury strips component”). The following summary of the terms of the Equity Units, the summary of the terms of the purchase contracts set forth under the caption “Description of the Purchase Contracts” and the summary of the terms of the U.S. treasury strips components set forth under the caption “Description of the U.S. Treasury Strips Components” below contain a description of all of the material terms of the Equity Units and their components but are not complete and are subject to, and qualified in their entirety by reference to, the related contracts. We refer you to the purchase contract agreement and the custodial agreement, which are incorporated by reference to this Annual Report on Form 10-K.

Components of the Equity Units

Each Equity Unit is comprised of:

• a prepaid forward stock purchase contract of PG&E Corporation entitling the holder to receive a number of shares of our Common Stock on August 16, 2023 (subject to postponement in certain limited circumstances, the “purchase contract settlement date”), or earlier if a “fundamental change” occurs prior to the settlement date or if the holder has elected “early settlement” (in each case, as defined herein and described below), determined by reference to the settlement rate described below; and

• a U.S. treasury strips component.

Unless previously settled at the holder’s option as described in “Description of the Purchase Contracts-Early Settlement” or “Description of the Purchase Contracts-Early Settlement Upon a Fundamental Change,” we will deliver to the holder, on the purchase contract settlement date, in respect of each purchase contract not more than 10.5263 shares of our Common Stock and not less than 8.5929 shares of our Common Stock, based upon the applicable “settlement rate” (as defined below), which is subject to adjustment as described herein, and the “applicable market value” (as defined below) of our Common Stock, as described below under “Description of the Purchase Contracts-Delivery of Common Stock.”

Each holder of Equity Units will be paid the amount received by the custodian from the U.S. government in respect of each U.S. treasury strip underlying the Equity Units owned by such holder on the business day immediately following the date such U.S. treasury strip matures on February 15, May 15, August 15 and November 15 of each year, with such payments commencing on, and including, August 17, 2020, and ending on, and including, August 16, 2023, as described below under “Description of the U.S. Treasury Strips Components.”

The stated amount of each Equity Unit must be allocated between the U.S. treasury strips component and the purchase contract based upon their relative fair market values. We have determined that the fair market value of each U.S. treasury strips component is $17.1402 and the fair market value of each purchase contract is $82.8574. Each holder agrees to such allocation and this position is binding upon each holder (but not on the Internal Revenue Service).

Separating and Recreating Equity Units

Upon the conditions and under the circumstances described below, a holder of 48,000 Equity Units (or any integral multiple thereof) has the right to separate its Equity Units into its component parts, and a holder of 48,000 separate purchase contracts (or any integral multiple thereof) and the underlying U.S. treasury strips has the right to combine these components to recreate 48,000 Equity Units (or any integral multiple thereof).

Separating Equity Units

At initial issuance, the purchase contracts and U.S. treasury strips components may be purchased and transferred only as Equity Units and will trade under the CUSIP number for the Equity Units.

On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, a holder of 48,000 Equity Units (or any integral multiple thereof) will have the right to separate such Equity Units and withdraw the U.S. treasury strips underlying those Equity Units. Because each Equity Unit evidences a 1/48,000th beneficial ownership interest in specified U.S. treasury strips, any separation of Equity Units

may be made only in integral multiples of 48,000 Equity Units. To withdraw the U.S. treasury strips evidenced by the Equity Units, the holder must:

• deliver the relevant Equity Units to the purchase contract agent; and

• deliver a notice to the purchase contract agent requesting that the purchase contract agent instruct the custodian to release to the holder the U.S. treasury strips underlying those Equity Units.

The purchase contract agent will then (i) cancel the Equity Units and deliver to the holder the purchase contracts underlying those Equity Units, which we refer to as “separate purchase contracts” and (ii) instruct the custodian to deliver to the holder the underlying U.S. treasury strips. If the holder has withdrawn the U.S. treasury strips previously underlying an Equity Unit, it may either continue to hold the separate purchase contract in global form through the purchase contract agent or receive a certificate for its separate purchase contract and hold it directly as the owner registered on the purchase contract register maintained on our behalf by the purchase contract registrar. Any administrative fees and expenses related to withdrawing the U.S. treasury strips evidenced by the Equity Units that are payable to the purchase contract agent or the custodian will be at the expense of the holder of Equity Units requesting withdrawal.

“Business day”means any day other than a Saturday, Sunday or any day on which banking institutions in New York, New York are authorized or obligated by applicable law or executive order to close or be closed.

There is no current or expected trading market for the separate purchase contracts and we do not intend to apply to have the separate purchase contracts listed on any securities exchange or quoted on any automated quotation system. Accordingly, we do not expect there to be a liquid market in the separate purchase contracts at any time. Separate purchase contracts and the withdrawn U.S. treasury strips will be transferable independently from each other.

Recreating Equity Units

On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, a holder of 48,000 separate purchase contracts (or any integral multiple thereof) will have the right to recreate Equity Units by delivering, for every 48,000 Equity Units being recreated, (i) to the purchase contract agent, 48,000 separate purchase contracts, and (ii) to the custodian, $66,000 face amount (or $33,000 face amount in the case of the U.S. treasury strips maturing on August 15, 2020) of each of the U.S. treasury strips that would be then remaining as a portion of the U.S. treasury strips component of an Equity Unit. Any recreation of Equity Units may be made only in integral multiples of 48,000 Equity Units. R'The newly deposited U.S. treasury strips used to recreate the Equity Units must have the same CUSIP numbers as the ones originally comprising the U.S. treasury strips component.

Global Securities

Each Equity Unit and purchase contract are represented by global securities registered in the name of a nominee of The Depository Trust Company (“DTC”). Holders are not entitled to receive definitive physical certificates for the Equity Units and purchase contracts, except under the limited circumstances described under “Book-Entry Procedures and Settlement.” Beneficial interests in an Equity Unit and, after separation, the separate purchase contract, will be represented through book-entry accounts of, and transfers will be effected through, direct or indirect participants in DTC.

Deemed Actions by Holders by Acceptance

Each holder of Equity Units or separate purchase contracts, by acceptance of such securities, is deemed to have:

• irrevocably authorized and directed the purchase contract agent to execute, deliver and perform on its behalf the purchase contract agreement, and appointed the purchase contract agent as its attorney-in-fact for any and all such purposes;

• in the case of a purchase contract that is a component of an Equity Unit, or that is evidenced by a separate purchase contract, irrevocably authorized and directed the purchase contract agent to execute, deliver and hold on its behalf the separate purchase contract or the component purchase contract evidencing such purchase contract, and appointed the purchase contract agent as its attorney-in-fact for any and all such purposes;

• consented to, and agreed to be bound by, the terms and provisions of the purchase contract agreement;

• in the case of a holder of an Equity Unit, agreed, for all purposes, including U.S. federal income tax purposes, to treat:

• an Equity Unit as an investment unit composed of two separate instruments, in accordance with its form;

• the allocation of the stated amount per Equity Unit between the purchase contract and the U.S. treasury strips component so that such holder’s initial tax basis in each purchase contract will be $82.8574 and such holder’s initial tax basis in each U.S. treasury strips component will be $17.1402;

• represented and warranted that neither the beneficial holder of the purchase contracts (including for these purposes a purchase contract that is a component of any Equity Unit) nor, to the knowledge of such beneficial holder, any other person, would become a “Substantial Shareholder” (as defined in the Amended Articles) as a result of such beneficial holder’s acquisition of purchase contracts (treating the beneficial holder and any such other person as actually holding, solely for purposes of this representation, the number of shares of our Common Stock that would be received upon settlement at the maximum settlement rate of all purchase contracts acquired or beneficially owned by such beneficial holder or any such other person, as applicable, but treating all other purchase contracts as still unsettled), and, for the avoidance of doubt, taking into account such beneficial holder’s and any such other person’s (i) current ownership of our Common Stock and any of the Utility’s preferred stock and (ii) other acquisitions of our Common Stock and any of the Utility’s preferred stock (if any) concurrent with or in connection with such beneficial holder’s acquisition of purchase contracts; and

• appointed the custodian to hold on its behalf and to receive payments related to the U.S. treasury strips components and agreed to indemnify the custodian from and against any liability it may incur in connection with such appointment in the absence of gross negligence or willful misconduct on its part.

Listing of Securities

Our Equity Units are listed on the NYSE under the symbol “PCGU.” However, listing on the NYSE does not guarantee that a trading market will develop, and the underwriters may discontinue market making at any time in their sole discretion without prior notice to Equity Unit holders. Accordingly, there can be no assurance that a liquid trading market will develop for the Equity Units (or, if developed, that a liquid trading market will be maintained), that the holder will be able to sell Equity Units at a particular time or that the prices the holder receives when the holder sells will be favorable.

Title

The purchase contract agent may treat the registered owner of any Equity Unit, which at initial issuance was a nominee of DTC, or, upon withdrawal of the U.S. treasury strips, the registered owner of any separate purchase contract, as the absolute owner thereof for the purpose of making payment and settling the purchase contracts and for all other purposes. Similarly, the custodian may treat the registered owner of any Equity Unit as the absolute owner thereof for the purpose of making payments of the U.S. treasury strips components and deliveries of the underlying U.S. treasury strips, if applicable, and for all other purposes.

Accounting for the Equity Units

We record the issuance of the purchase contract portion of the Equity Units as Common Stock, net of issuance costs of the purchase contracts, in our financial statements. All of the proceeds from the issuance of the U.S. treasury strips components were paid to the custodian, and we did not receive any proceeds from such issuance.

Based on U.S. GAAP, we do not expect the purchase contract component of the Equity Units to be revalued under fair value accounting principles.

Our earnings per share calculations will reflect the shares issuable upon settlement of the purchase contracts portion of the Equity Units. Our basic earnings per share will include the minimum shares issuable under the purchase contract for each period and our diluted earnings per share will include any incremental shares that would be issuable assuming a settlement of the purchase contract at the end of each accounting period, if dilutive.

Replacement of Equity Unit Certificates

In the event that physical certificates evidencing the Equity Units have been issued, any mutilated equity unit certificate will be replaced by us at the expense of the holder upon surrender of the certificate to the purchase contract agent. Equity Unit certificates that have been destroyed, lost or stolen will be replaced by us at the expense of the holder upon delivery to us and the purchase contract agent of evidence of their destruction, loss or theft satisfactory to us and the purchase contract agent. In the case of a destroyed, lost or stolen Equity Unit certificate, an indemnity satisfactory to us and the purchase contract agent may be required at the expense of the holder of the Equity Units before a replacement will be issued.

Notwithstanding the foregoing, we will not be obligated to replace any Equity Unit certificates on or after the second scheduled trading day immediately preceding August 16, 2023 or any early settlement date. In those circumstances, the purchase contract agreement will provide that, in lieu of the delivery of a replacement Equity Unit certificate, the purchase contract agent, upon delivery of the evidence and indemnity described above, will deliver or arrange for delivery of the shares of Common Stock issuable pursuant to the purchase contracts included in the Equity Units evidenced by the Equity Unit certificate.

Miscellaneous

The purchase contract agreement provides that we will pay all fees and expenses related to the offering of the Equity Units and the enforcement by the purchase contract agent of the rights of the holders of the Equity Units or the separate purchase contracts, other than expenses (including legal fees) of the underwriters.

Should the holder elect to separate or recreate Equity Units, the holder will be responsible for any fees or expenses payable in connection with that separation or recreation, and we will have no liability therefor.

Description of the Purchase Contracts

The purchase contracts are issued pursuant to the terms and provisions of the purchase contract agreement. The following summary contains a description of all of the material terms of the purchase contracts but is not complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of the purchase contract agreement, including the definitions in the purchase contract agreement of certain terms. We refer you to the purchase contract agreement which is incorporated by reference to this Annual Report on Form 10-K.

Each purchase contract will initially form a part of an Equity Unit. On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, the holder will have the right to separate 48,000 Equity Units (or any integral multiple thereof) and withdraw the U.S. treasury strips underlying those Equity Units. Following such separation, purchase contracts may be transferred separately from the U.S. treasury strips components.

Delivery of Common Stock

Unless settled early at the holder’s option, for each purchase contract we will deliver to the holder on August 16, 2023 (subject to postponement in certain limited circumstances described below, the “purchase contract settlement date”), a number of shares of our Common Stock. The number of shares of our Common Stock issuable upon settlement of each purchase contract (the “settlement rate”) will be determined by us as follows:

• if the applicable market value of our Common Stock is greater than the threshold appreciation price, then the holder will receive 8.5929 shares of Common Stock for each purchase contract (the “minimum settlement rate”);

• if the applicable market value of our Common Stock is greater than or equal to the reference price but less than or equal to the threshold appreciation price, then the holder will receive a number of shares of Common Stock for each purchase contract equal to the Equity Unit stated amount of $100, divided by the applicable market value; and

• if the applicable market value of our Common Stock is less than the reference price, then the holder will receive 10.5263 shares of Common Stock for each purchase contract (the “maximum settlement rate”).

The maximum settlement rate and minimum settlement rate are each subject to adjustment as described under “-Anti-Dilution Adjustments to the Fixed Settlement Rates” below. Each of the minimum settlement rate and the maximum settlement rate is referred to as a “fixed settlement rate.”

The reference price is equal to $100 divided by the maximum settlement rate and is approximately equal to $9.5000.

The threshold appreciation price is equal to $100 divided by the minimum settlement rate. The threshold appreciation price, which is initially approximately $11.6375, represents an appreciation of approximately 22.50% over the reference price.

For illustrative purposes only, the following table shows the number of shares of Common Stock issuable upon settlement of a purchase contract at assumed applicable market values, based on a reference price of $9.5000 and a threshold appreciation price of $11.6375. The table assumes that there will be no adjustments to the fixed settlement rates described below under “-Anti-Dilution Adjustments to the Fixed Settlement Rates” below or settled early at the option of holders as described under “-Early Settlement” or “-Early Settlement Upon a Fundamental Change” below. There can be no assurance that the actual applicable market value will be within the assumed range set forth below.

A holder of an Equity Unit or a separate purchase contract, as applicable, would receive on the purchase contract settlement date the following numbers of shares of Common Stock for each Equity Unit or separate purchase contract at the following assumed applicable market values:

Assumed Applicable Market Value	Number of Shares of Common Stock
$2.00		10.5263
$4.00		10.5263
$6.00		10.5263
$8.00		10.5263
$9.50		10.5263
$10.50		9.5238
$11.64		8.5929
$13.00		8.5929
$15.00		8.5929
$18.00		8.5929
$21.00		8.5929
$25.00		8.5929
$30.00		8.5929
$35.00		8.5929

As the above table illustrates, if, on the purchase contract settlement date, the applicable market value is greater than the threshold appreciation price, we would be obligated to deliver 8.5929 shares of Common Stock for each purchase contract.

If, on the purchase contract settlement date, the applicable market value is less than or equal to the threshold appreciation price but greater than or equal to the reference price of approximately $9.5000, we would be obligated to deliver a number of shares of our Common Stock on the purchase contract settlement date equal to $100, divided by the applicable market value. As a result, we would retain all appreciation in the market value of our Common Stock underlying each purchase contract between the reference price and the threshold appreciation price.

If, on the purchase contract settlement date, the applicable market value is less than the reference price of approximately $9.5000, we would be obligated to deliver upon settlement of the purchase contract 10.5263 shares of Common Stock for each purchase contract, regardless of the market price of our Common Stock. As a result, the holder would suffer the full decline in market value of the Common Stock below the reference price.

Because the applicable market value of the Common Stock is determined over the “valuation period” (as defined below), the number of shares of Common Stock delivered for each purchase contract may be greater than or less than the number that would have been delivered based on the closing price (or daily VWAP) of the Common Stock on the last trading day of such valuation period. In addition, the holder will bear the risk of fluctuations in the market price of the shares of Common Stock deliverable upon settlement of the purchase contracts between the end of such valuation period and the date such shares are delivered.

The term “applicable market value” means the arithmetic average of the daily VWAPs of our Common Stock on each trading day of the valuation period.

The term “valuation period” means each of the 20 consecutive trading days beginning on, and including, the 21st scheduled trading day immediately preceding August 16, 2023.

The “daily VWAP” of our Common Stock on any trading day means the per share volume-weighted average price as displayed under the heading “Bloomberg VWAP” on Bloomberg page “PCG <equity> AQR” (or its equivalent successor if such page is not available) in respect of the period from the scheduled open of trading until the scheduled close of trading of the primary trading session on such trading day (or if such volume-weighted average price is unavailable, the market value of one share of our Common Stock on such trading day determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained for this purpose by us). The “daily VWAP” will be determined without regard to after-hours trading or any other trading outside of the regular trading session trading hours. The “average VWAP” per share over a certain period means the arithmetic average of the daily VWAP per share for each trading day in such period.

“Trading day” means a day on which (i) there is no “market disruption event” (as defined below) and (ii) trading in our Common Stock (or other security for which a daily VWAP must be determined) generally occurs on the NYSE or, if our Common Stock (or such other security) is not then listed on the NYSE, on the principal other U.S. national or regional securities exchange on which our Common Stock (or such other security) is then listed or, if our Common Stock (or such other security) is not then listed on a U.S. national or regional securities exchange, on the principal other market on which our Common Stock (or such other security) is then traded. If our Common Stock (or such other security) is not so listed or traded, “trading day” means a “business day.”

“Scheduled trading day” means a day that is scheduled to be a trading day on the NYSE or, if our Common Stock is not then listed on the NYSE, on the principal other U.S. national or regional securities exchange on which our Common Stock is then listed or, if our Common Stock is not then listed on a U.S. national or regional securities exchange, on the principal other market on which our Common Stock is then traded. If our Common Stock is not so listed or admitted for trading, “scheduled trading day” means a “business day.”

“Market disruption event” means (i) a failure by the primary U.S. national or regional securities exchange or market on which our Common Stock is listed or admitted for trading to open for trading during its regular trading session or (ii) the occurrence or existence prior to 1:00 p.m., New York City time, on any scheduled trading day for our Common Stock for more than one half-hour period in the aggregate during regular trading hours of any suspension or limitation imposed on trading (by reason of movements in price exceeding limits permitted by the relevant stock exchange, relevant market or otherwise) in our Common Stock or in any options contracts or futures contracts relating to our Common Stock.

On the purchase contract settlement date, our Common Stock will be issued and delivered to the holder or the holder’s designee, upon (i) surrender of certificates representing the purchase contracts, if such purchase contracts

are held in certificated form, and (ii) payment by the holder of any transfer or similar taxes payable in connection with the issuance of our Common Stock to any person other than the holder. As long as the purchase contracts are evidenced by one or more global purchase contract certificates deposited with DTC, procedures for settlement will be governed by DTC’s applicable procedures.

If one or more of the 20 consecutive scheduled trading days in the valuation period is not a trading day, the purchase contract settlement date will be postponed until the second business day immediately following the last trading day of the valuation period.

Prior to 5:00 p.m., New York City time, on the last trading day of the valuation period, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of such purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our Common Stock by virtue of holding such purchase contract. The person in whose name any shares of our Common Stock shall be issuable upon settlement of the purchase contract on the purchase contract settlement date will be treated as the holder of record of such shares as of 5:00 p.m., New York City time, on the last trading day of the 20 consecutive trading day period during which the applicable market value is determined.

We will pay any documentary, stamp or similar issue or transfer tax due on the issue of any shares of our Common Stock upon settlement of the purchase contracts, unless the tax is due because the holder requests any shares to be issued in a name other than the holder’s name, in which case the holder will pay that tax.

Early Settlement

Prior to 5:00 p.m., New York City time on the second scheduled trading day immediately preceding August 16, 2023, any holder of 48,000 Equity Units (or any integral multiple thereof) or a holder of one or more separate purchase contracts, may elect to settle such Equity Units or separate purchase contracts early and receive a number of shares of Common Stock per purchase contract equal to the “early settlement rate.” The early settlement rate is equal to the minimum settlement rate on the early settlement date, subject to adjustment as described below under “-Anti-Dilution Adjustments to the Fixed Settlement Rates,” unless the holder elects to settle the holder’s purchase contracts early in connection with a fundamental change, in which case the holder will receive upon settlement of the holder’s purchase contracts a number of shares of our Common Stock based on the “fundamental change early settlement rate” as described under “-Early Settlement Upon a Fundamental Change.” We refer to this right as the “early settlement right.”

The holder’s right to receive Common Stock upon early settlement of a purchase contract is subject to (i) delivery of a written and signed notice of election (an “early settlement notice”) to the purchase contract agent electing early settlement of such purchase contract, (ii) if such purchase contract or the Equity Unit that includes such purchase contract is held in certificated form, surrendering the certificates representing the purchase contract and (iii) payment by the holder of any transfer or similar taxes payable in connection with the issuance of our Common Stock to any person other than the holder. As long as the purchase contracts or the Equity Units are evidenced by one or more global certificates deposited with DTC, procedures for early settlement will be governed by DTC’s applicable procedures.

Upon surrender of the Equity Unit or the separate purchase contract, as applicable, and payment of any applicable transfer or similar taxes due because of any issue of such shares in a name of a person other than the holder, the holder will receive the applicable number of shares of Common Stock (and any cash payable for fractional shares) due upon early settlement on the second business day following the “early settlement date” (as defined below).

If the holder complies with the requirements for effecting the early settlement right prior to 5:00 p.m., New York City time, on any business day, then that day will be considered the “early settlement date.” If the holder complies with such requirements at or after 5:00 p.m., New York City time, on any business day or at any time on a day that is not a business day, then the next succeeding business day will be considered the “early settlement date.” Prior to 5:00 p.m., New York City time, on the early settlement date, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of such purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our Common Stock by virtue of holding such purchase contract. The person in whose name any shares of our Common Stock shall be issuable upon such early settlement of the purchase contract will be treated as the holder of record of such shares as of 5:00 p.m., New York City time, on the relevant early settlement date.

Because each Equity Unit evidences a 1/48,000th beneficial ownership interest in specified U.S. treasury strips, any early settlement of Equity Units may be made only in integral multiples of 48,000 Equity Units.

Upon early settlement at the holder’s election of purchase contracts held as components of Equity Units, the custodian will deliver the U.S. treasury strips evidenced by those Equity Units to such holder free and clear of any liens or other encumbrances on the second business day following the early settlement date.

Early Settlement Upon a Fundamental Change

If a “fundamental change” occurs and the holder elects to settle the holder’s purchase contracts early in connection with such fundamental change in accordance with the procedures described under “-Early Settlement” above, the holder will receive per purchase contract a number of shares of our Common Stock or cash, securities or other property, as applicable, equal to the “fundamental change early settlement rate,” as described below. An early settlement will be deemed for these purposes to be “in connection with” such fundamental change if the holder delivers the holder’s early settlement notice to the purchase contract agent, and otherwise satisfies the requirements for effecting early settlement of the holder’s purchase contracts, during the period beginning on, and including, the effective date of the fundamental change and ending at 5:00 p.m., New York City time, on the 35th business day thereafter (or, if earlier, the second scheduled trading day immediately preceding August 16, 2023) (the “fundamental change early settlement period”). We refer to this right as the “fundamental change early settlement right.”

If the holder complies with the requirements for effecting the fundamental change early settlement right prior to 5:00 p.m., New York City time, on any business day during the fundamental change early settlement period, then that day will be considered the “fundamental change early settlement date.” If the holder complies with such requirements at or after 5:00 p.m., New York City time, on any business day during the fundamental change early settlement period or at any time on a day during the fundamental change early settlement period that is not a business day, then the next succeeding business day will be considered the “fundamental change early settlement date.”

Any early settlement of Equity Units in connection with a fundamental change may be made only in integral multiples of 48,000 Equity Units.

We will provide the purchase contract agent, custodian and the holders of Equity Units and separate purchase contracts with a notice of a fundamental change within five business days after its effective date and issue a press release announcing such effective date. The notice will also set forth, among other things, (i) the applicable fundamental change early settlement rate, (ii) if not Common Stock, the kind and amount of cash, securities and other property receivable by the holder upon settlement and (iii) the deadline by which each holder’s fundamental change early settlement right must be exercised.

A “fundamental change” will be deemed to have occurred upon the occurrence of any of the following:

• any “person” or “group” within the meaning of Section 13(d) of the Exchange Act of 1934, as amended (the “Exchange Act”), other than us, any of our wholly owned subsidiaries and any of our and their employee benefit plans, files a Schedule TO or any other schedule, form or report under the Exchange Act disclosing that such person or group has become the direct or indirect “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act) of more than 50% of the outstanding shares of our Common Stock;

• the consummation of (A) any recapitalization, reclassification or change of our Common Stock (other than changes resulting from a subdivision or combination) as a result of which our Common Stock would be converted into, or exchanged for, stock, other securities, other property or assets; (B) any share exchange, consolidation or merger of us pursuant to which our Common Stock will be converted into cash, securities or other property or assets; or (C) any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of us and our subsidiaries, taken as a whole, to any person other than one of our wholly owned subsidiaries; or

• our Common Stock (or other Common Stock receivable upon settlement of the holder’s purchase contracts, if applicable) ceases to be listed or quoted on any of the NYSE, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors).

A transaction or transactions described in either of the first two bullets above will not constitute a fundamental change, however, if (i) at least 90% of the consideration received or to be received by stockholders of our Common Stock (excluding cash payments for fractional shares) in connection with such transaction or transactions consists of shares of Common Stock that are listed on any of the NYSE, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors), or will be so listed when issued or exchanged in connection with such transaction or transactions and (ii) as a result of such transaction or transactions such consideration becomes the consideration receivable upon settlement of the holder’s purchase contracts, if applicable, excluding cash payments for fractional shares.

If any transaction in which our Common Stock is replaced by the securities of another entity occurs, following completion of any related fundamental change early settlement period (or, in the case of a transaction that would have been a fundamental change but for the immediately preceding paragraph, following the effective date of such transaction), references to us in the definition of “fundamental change” above shall instead be references to such other entity.

The “fundamental change early settlement rate” will be determined by us by reference to the table below, based on the date on which the fundamental change occurs or becomes effective (the “fundamental change effective date”) and the “stock price” in the fundamental change, which will be:

• in the case of a fundamental change described in the second bullet of the definition of “fundamental change” in which all holders of shares of our Common Stock receive only cash in the fundamental change, the stock price will be the cash amount paid per share of our Common Stock; and

• in all other cases, the stock price will be the arithmetic average of the daily VWAPs of our Common Stock over the five consecutive trading day period ending on the trading day immediately preceding such fundamental change effective date.

The stock prices set forth in the column headings of the table below will be adjusted as of any date on which the fixed settlement rates are adjusted. The adjusted stock prices will equal the stock prices applicable immediately prior to such adjustment, multiplied by a fraction, the numerator of which is the maximum settlement rate immediately prior to the adjustment giving rise to the stock price adjustment and the denominator of which is the maximum settlement rate as so adjusted. The fundamental change early settlement rates per purchase contract in the table below will be adjusted in the same manner and at the same time as the fixed settlement rates as set forth under “-Anti-Dilution Adjustments to the Fixed Settlement Rates.”

The following table sets forth the fundamental change early settlement rate per purchase contract for each stock price and fundamental change effective date set forth below:

Stock Price
Fundamental Change Effective Date	$	2.00	$	4.00	$	6.00	$	8.00	$	9.50	$	10.50	$	11.64	$	13.00	$	15.00	$	18.00
July 1, 2020	10.3248		9.9939		9.5052		9.0924		8.8699		8.7592		8.663		8.5811		8.5065		8.4547
August 16, 2020	10.3372		10.0252		9.5399		9.12		8.8914		8.7774		8.6781		8.5936		8.5167		8.4633
February 16, 2021	10.3813		10.1499		9.6883		9.2397		8.9836		8.8538		8.7404		8.6438		8.5564		8.4966
August 16, 2021	10.417		10.2681		9.852		9.3763		9.0862		8.9361		8.8043		8.6924		8.5927		8.5265
February 16, 2022	10.4472		10.3753		10.0399		9.5445		9.2088		9.0297		8.8715		8.7386		8.6236		8.5521
August 16, 2022	10.4738		10.4551		10.2454		9.7595		9.3615		9.137		8.9374		8.7734		8.6408		8.5695
February 16, 2023	10.5002		10.4998		10.4479		10.0823		9.5949		9.276		8.9882		8.7694		8.6265		8.5775
August 16, 2023	10.5263		10.5263		10.5263		10.5263		10.5263		9.5238		8.5929		8.5929		8.5929		8.5929

The exact stock prices and fundamental change effective dates may not be set forth in the table above, in which case:

• if the applicable stock price is between two stock prices in the table or the applicable fundamental change effective date is between two fundamental change effective dates in the table, the fundamental change early settlement rate will be determined by straight line interpolation between the fundamental change early settlement rates set forth for the higher and lower stock prices and the earlier and later fundamental change effective dates, as applicable, based on a 365- or 366-day year, as applicable;

• if the applicable stock price is greater than $35.00 per share (subject to adjustment in the same manner and at the same time as the stock prices set forth in the column headings of the table above), then the fundamental change early settlement rate will be the minimum settlement rate; or

• if the applicable stock price is less than $2.00 per share (subject to adjustment in the same manner and at the same time as the stock prices set forth in the column headings of the table above, the “minimum stock price”), the fundamental change early settlement rate will be determined as if the stock price equaled the minimum stock price, and using straight line interpolation, as described in the first bullet of this paragraph, if the fundamental change effective date is between two fundamental change effective dates in the table.

The maximum number of shares of our Common Stock deliverable under a purchase contract is 10.5263, subject to adjustment in the same manner and at the same time as the fixed settlement rates as set forth under “-Anti-Dilution Adjustments to the Fixed Settlement Rates.”

Our obligation to settle the purchase contracts at the fundamental change early settlement rate could be considered a penalty, in which case the enforceability thereof would be subject to general principles of reasonableness of economic remedies.

We will deliver the shares of our Common Stock, securities, cash or other property payable as a result of the holder’s exercise of the fundamental change early settlement right on the second business day following the fundamental change early settlement date. Prior to 5:00 p.m., New York City time, on the fundamental change early settlement date, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of such purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our Common Stock by virtue of holding such purchase contract. The person in whose name any shares of our Common Stock or other securities, if applicable, shall be issuable following exercise of a holder’s fundamental change early settlement right will be treated as the holder of record of such shares or other securities, if applicable, as of 5:00 p.m., New York City time, on the fundamental change early settlement date.

Upon early settlement of purchase contracts held as components of Equity Units at the holder’s election upon a fundamental change, the custodian will deliver the U.S. treasury strips evidenced by those Equity Units to such holder free and clear of any liens or other encumbrances on the second business day following the fundamental change early settlement date.

If the holder does not elect to exercise the holder’s fundamental change early settlement right, the holder’s purchase contracts will remain outstanding and will be subject to normal settlement on any subsequent early settlement date or any subsequent fundamental change early settlement date, as the case may be.

Anti-Dilution Adjustments to the Fixed Settlement Rates

Each fixed settlement rate will be adjusted as described below, except that we will not make any adjustments to the fixed settlement rates if holders of the purchase contracts participate (other than in the case of a share split or share combination or a tender or exchange offer described in clause (5) below), at the same time and upon the same terms as holders of our Common Stock and solely as a result of holding the purchase contracts, in any of the transactions described below without having to settle their purchase contracts as if they held a number of shares of Common Stock equal to (i) the maximum settlement rate as of the record date for such transaction, multiplied by (ii) the number of purchase contracts held by such holder.

(1) If we exclusively issue shares of our Common Stock as a dividend or distribution on shares of our Common Stock, or if we effect a share split or share combination, each fixed settlement rate will be adjusted based on the following formula:

CR1 = CR0 x	OS1
	OS0

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date (as defined below) of such dividend or distribution, or immediately prior to the open of business on the effective date of such share split or share combination, as applicable;
CR1	=	such fixed settlement rate in effect immediately after the close of business on such record date or immediately after the open of business on such effective date, as applicable;
OS0	=	the number of shares of our Common Stock outstanding immediately prior to the close of business on such record date or immediately prior to the open of business on such effective date, as applicable, before giving effect to such dividend, distribution, share split or share combination; and
OS1	=	the number of shares of our Common Stock outstanding immediately after giving effect to such dividend, distribution, share split or share combination.

Any adjustment made under this clause (1) shall become effective immediately after the close of business on the record date for such dividend or distribution, or immediately after the open of business on the effective date for such share split or share combination, as applicable. If any dividend or distribution of the type described in this clause (1) is declared but not so paid or made, each fixed settlement rate shall be immediately readjusted, effective as of the date our board of directors or a committee thereof determines not to pay such dividend or distribution, to such fixed settlement rate that would then be in effect if such dividend or distribution had not been declared. For the purposes of this clause (1), the number of shares of our Common Stock outstanding immediately prior to the close of business on the relevant record date or immediately prior to the open of business on the relevant effective date, as the case may be, and the number of shares of our Common Stock outstanding immediately after giving effect to such dividend, distribution, share split or share combination shall, in each case, not include shares that we hold in treasury. We will not pay any dividend or make any distribution on shares of our Common Stock that we hold in treasury.

“Effective date” as used in this clause (1) means the first date on which the shares of our Common Stock trade on the relevant stock exchange, regular way, reflecting the relevant share split or share combination, as applicable.

“Record date” means, with respect to any dividend, distribution or other transaction or event in which the holders of our Common Stock (or other applicable security) have the right to receive any cash, securities or other property or in which our Common Stock (or such other security) is exchanged for or converted into any combination of cash, securities or other property, the date fixed for determination of holders of our Common Stock (or such other security) entitled to receive such cash, securities or other property (whether such date is fixed by our board of directors or a duly authorized committee thereof, statute, contract or otherwise).

(2) If we issue to all or substantially all holders of our Common Stock any rights, options or warrants entitling them, for a period of not more than 45 calendar days after the announcement date of such issuance, to subscribe for or purchase shares of our Common Stock at a price per share that is less than the average VWAP per share of our Common Stock for the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of such issuance, each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	OS0 + X
	OS0 + Y

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date for such issuance;
CR1	=	such fixed settlement rate in effect immediately after the close of business on such record date;
OS0	=	the number of shares of our Common Stock outstanding immediately prior to the close of business on such record date;
X	=	the total number of shares of our Common Stock issuable pursuant to such rights, options or warrants; and
Y	=	the number of shares of our Common Stock equal to (i) the aggregate price payable to exercise such rights, options or warrants, divided by (ii) the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of the issuance of such rights, options or warrants.

Any increase made under this clause (2) will be made successively whenever any such rights, options or warrants are issued and shall become effective immediately after the close of business on the record date for such issuance. To the extent that such rights, options or warrants are not exercised prior to their expiration or shares of Common Stock are not delivered after the exercise of such rights, options or warrants, each fixed settlement rate shall be decreased to such fixed settlement rate that would then be in effect had the increase with respect to the issuance of such rights, options or warrants been made on the basis of delivery of only the number of shares of Common Stock actually delivered, if any. If such rights, options or warrants are not so issued, each fixed settlement rate shall be immediately readjusted, effective as of the date our board of directors or a committee thereof determines not to issue such rights, options or warrants to such fixed settlement rate that would then be in effect if such record date for such issuance had not occurred.

For the purpose of this clause (2), in determining whether any rights, options or warrants entitle the holders of our Common Stock to subscribe for or purchase shares of our Common Stock at less than such average VWAP per share for the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of such issuance, and in determining the aggregate offering price of such shares of our Common Stock, there shall be taken into account any consideration received by us for such rights, options or warrants and any amount payable on exercise or conversion thereof, the value of such consideration, if other than cash, to be determined by our board of directors in good faith.

(3) If we distribute shares of our capital stock, evidences of our indebtedness, other assets or property of ours or rights, options or warrants to acquire our capital stock or other securities, to all or substantially all holders of our Common Stock, excluding:

• dividends, distributions or issuances as to which the provisions set forth in clause (1) or (2) shall apply;

• dividends or distributions paid exclusively in cash as to which the provisions set forth in clause (4) below shall apply;

• any distributions upon conversion of, or in exchange for, our Common Stock in connection with a recapitalization, reclassification, change, consolidation, merger or other combination, share exchange, or sale, lease or other transfer or disposition resulting in the change in the consideration due upon settlement of the purchase contracts as described below under “-Recapitalizations, Reclassifications and Changes of Our Common Stock”;

• except as otherwise described below, rights issued pursuant to a shareholder rights plan adopted by us; and

• spin-offs as to which the provisions set forth below in this clause (3) shall apply;

then each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	SP0
	SP0 - FMV

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date for such distribution;
CR1	=	such fixed settlement rate in effect immediately after the close of business on such record date;
SP0	=	the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the trading day immediately preceding the ex-date (as defined below) for such distribution; and
FMV	=	the fair market value (as determined by our board of directors in good faith) of the shares of capital stock, evidences of indebtedness, assets, property, rights, options or warrants so distributed, expressed as an amount per share of our Common Stock on the ex-date for such distribution.

“Ex-date” means the first date on which the shares of our Common Stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive the issuance, dividend or distribution in question, from us or, if applicable, from the seller of our Common Stock on such exchange or market (in the form of due bills or otherwise) as determined by such exchange or market.

Any increase made under the portion of this clause (3) above will become effective immediately after the close of business on the record date for such distribution. If such distribution is not so paid or made, each fixed settlement rate shall be immediately readjusted, effective as of the date our board of directors or a committee thereof determines not to pay such dividend or distribution, to be such fixed settlement rate that would then be in effect if such distribution had not been declared.

Notwithstanding the foregoing, if “FMV” (as defined above) is equal to or greater than “SP0” (as defined above), in lieu of the foregoing increase, each holder shall receive, in respect of each purchase contract, at the same time and upon the same terms as holders of our Common Stock, without having to settle such purchase contract, the amount and kind of our capital stock, evidences of our indebtedness, other assets or property of ours or rights, options or warrants to acquire our capital stock or other securities that such holder would have received if such holder owned a number of shares of Common Stock equal to the maximum settlement rate in effect on the record date for the distribution.

If we issue rights, options or warrants that are only exercisable upon the occurrence of certain triggering events, then:

• we will not adjust the fixed settlement rates pursuant to the foregoing in this clause (3) until the earliest of these triggering events occurs; and

• we will readjust the fixed settlement rates to the extent any of these rights, options or warrants are not exercised before they expire; provided that the rights, options or warrants trade together with our Common Stock and will be issued in respect of future issuances of the shares of our Common Stock.

With respect to an adjustment pursuant to this clause (3) where there has been a payment of a dividend or other distribution on our Common Stock of shares of capital stock of any class or series, or similar equity interest, of or relating to a subsidiary or other business unit, that are, or, when issued, will be, listed or admitted for trading on a U.S. national securities exchange, which we refer to as a “spin-off,” each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	FMV0 + MP0
	MP0

where,

CR0	=	such fixed settlement rate in effect immediately prior to the open of business on the ex-date for the spin-off;
CR1	=	such fixed settlement rate in effect immediately after the open of business on the ex-date for the spin-off;
FMV0	=	the average VWAP per share of the capital stock or similar equity interest distributed to holders of our Common Stock applicable to one share of our Common Stock over the ten consecutive trading day period commencing on, and including, the ex-date for the spin-off, or the “valuation period”; and
MP0	=	the average VWAP per share of our Common Stock over the valuation period.

The increase to each fixed settlement rate under the preceding paragraph will be calculated as of the close of business on the last trading day of the valuation period but will be given retroactive effect as of immediately after the open of business on the ex-date of the spin-off. Because we will make the adjustment to each fixed settlement rate with retroactive effect, we will delay the settlement of any purchase contract where any date for determining the number of shares of our Common Stock issuable to a holder occurs during the valuation period until the second business day after the last trading day of such valuation period. If such dividend or distribution is not so paid, each fixed settlement rate shall be decreased, effective as of the date our board of directors or a committee thereof determines not to make or pay such dividend or distribution, to be such fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.

(4) If any cash dividend or distribution is made to all or substantially all holders of our Common Stock, each fixed settlement rate will be adjusted based on the following formula:

CR1 = CR0 x	SP0
	SP0 - C

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the record date for such dividend or distribution;
CR1	=	such fixed settlement rate in effect immediately after the close of business on the record date for such dividend or distribution;
SP0	=	the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the Trading Day immediately preceding the ex-date for such distribution; and
C	=	the amount in cash per share we distribute to all or substantially all holders of our Common Stock.

Any increase made under this clause (4) shall become effective immediately after the close of business on the record date for such dividend or distribution. If such dividend or distribution is not so paid, each fixed settlement rate shall be decreased, effective as of the date our board of directors or a committee thereof determines not to make or pay such dividend or distribution, to be such fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.

Notwithstanding the foregoing, if “C” (as defined above) is equal to or greater than “SP0” (as defined above), in lieu of the foregoing increase, each holder shall receive, in respect of each purchase contract, at the same time and upon the same terms as holders of shares of our Common Stock, without having to settle such purchase contract, the amount of cash that such holder would have received if such holder owned a number of shares of our Common Stock equal to the maximum settlement rate on the record date for such cash dividend or distribution.

(5) If we or any of our subsidiaries make a payment in respect of a tender or exchange offer for our Common Stock, to the extent that the cash and value of any other consideration included in the payment per share of Common Stock exceeds the average VWAP per share of our Common Stock over the ten consecutive trading day period commencing on, and including, the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender or exchange offer, or the “expiration date”, each fixed settlement rate will be increased based on the following formula:

CR1 = CR0 x	AC + (SP1x OS1)
	OS0 x SP1

where,

CR0	=	such fixed settlement rate in effect immediately prior to the close of business on the expiration date;
CR1	=	such fixed settlement rate in effect immediately after the close of business on the expiration date;
AC	=	the aggregate value of all cash and any other consideration (as determined by our board of directors in good faith) paid or payable for shares purchased in such tender or exchange offer;
OS0	=	the number of shares of our Common Stock outstanding immediately prior to the expiration date (prior to giving effect to the purchase of all shares accepted for purchase or exchange in such tender or exchange offer);
OS1	=	the number of shares of our Common Stock outstanding immediately after the expiration date (after giving effect to the purchase of all shares accepted for purchase or exchange in such tender or exchange offer); and
SP1	=	the average VWAP of our Common Stock over the ten consecutive trading day period commencing on, and including, the trading day next succeeding the expiration date (the “averaging period”).

The increase to each fixed settlement rate under the preceding paragraph will be calculated at the close of business on the last trading day of the averaging period but will be given retroactive effect as of immediately after the close of business on the expiration date. Because we will make the adjustment to each fixed settlement rate with retroactive effect, we will delay the settlement of any purchase contracts where any date for determining the number of shares of our Common Stock issuable to a holder occurs during the averaging period until the second business day after the last trading day of such averaging period. For the avoidance of doubt, no adjustment under this clause (5) will be made if such adjustment would result in a decrease in any fixed settlement rate.

In the event that we or one of our subsidiaries is obligated to purchase shares of Common Stock pursuant to any such tender offer or exchange offer, but we or such subsidiary is permanently prevented by applicable law from effecting any such purchases, or all such purchases are rescinded, then each fixed settlement rate shall again be adjusted to be such fixed settlement rate that would then be in effect if such tender offer or exchange offer had not been made (or had been made only in respect of the purchases that have been made and not rescinded).

We may, to the extent permitted by law and the rules of NYSE or any other securities exchange on which our Common Stock or the purchase contracts is then listed, increase each fixed settlement rate by any amount for a period of at least 20 business days if such increase is irrevocable during such 20 business days and our board of directors (or a committee thereof) determines that such increase would be in our best interest. In addition, we may make such increases in each fixed settlement rate as we deem advisable in order to avoid or diminish any income tax to holders of our Common Stock resulting from any dividend or distribution of shares of our Common Stock (or issuance of rights or warrants to acquire shares of our Common Stock) or from any event treated as such for income tax purposes or for any other reason. We may only make such a discretionary adjustment if we make the same proportionate adjustment to each fixed settlement rate.

Beneficial owners of the purchase contracts may, in certain circumstances, including upon a distribution of cash dividends to holders of our shares of Common Stock, be deemed to have received a distribution subject to U.S. federal income tax as a dividend as a result of an adjustment or the nonoccurrence of an adjustment to the fixed settlement rates. See “Material United States Federal Income Tax Consequences.”

If we have a rights plan in effect upon settlement of the purchase contracts into Common Stock, the holder will receive, in addition to any shares of Common Stock received in connection with such settlement, the rights under the rights plan. However, if, prior to any settlement, the rights have separated from the shares of Common Stock in accordance with the provisions of the applicable rights plan, each fixed settlement rate will be adjusted at the time of separation as if we distributed to all or substantially all holders of our Common Stock, shares of our capital stock, evidences of indebtedness, assets, property, rights, options or warrants as described in clause (3) above, subject to

readjustment in the event of the expiration, termination or redemption of such rights. We do not currently have a stockholder rights plan in effect.

Adjustments to the fixed settlement rates will be calculated to the nearest 1/10,000th of a share of our Common Stock, and corresponding adjustments to the reference price and the threshold appreciation period will be calculated to the nearest $0.0001.

The fixed settlement rate will not be adjusted:

• upon the issuance of any shares of our Common Stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities and the investment of additional optional amounts in Common Stock under any plan;

• upon the issuance of any shares of our Common Stock or options, rights or warrants to purchase those shares pursuant to any present or future benefit or other incentive plan or program of or assumed by us or any of our subsidiaries;

• subject to the second immediately preceding paragraph, upon the issuance of any shares of our Common Stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security not described in the preceding bullet and outstanding as of the date the purchase contracts were first issued;

• for a change in the par value of our Common Stock;

• for stock repurchases that are not tender or exchange offers referred to in clause (5) of the adjustments above, including structured or derivative transactions or pursuant to a stock repurchase program approved by our board of directors that is not a tender or exchange offer referred to in clause (5).

Except as otherwise provided above, we will be responsible for making all calculations called for under the purchase contracts. These calculations include, but are not limited to, determinations of the fundamental change early settlement rate, the stock price in connection with a fundamental change, the daily VWAP, the average VWAPs and the fixed settlement rates of the purchase contracts.

We will be required, within ten business days after the fixed settlement rates are adjusted, to provide or cause to be provided written notice of the adjustment to the holders of the purchase contracts. We will also deliver to the purchase contract agent a certificate setting forth in reasonable detail the method by which the adjustment to each fixed settlement rate was determined and setting forth each adjusted fixed settlement rate.

For the avoidance of doubt, if an adjustment is made to the fixed settlement rates, no separate inversely proportionate adjustment will be made to the reference price or the threshold appreciation price because the reference price is equal to $100 divided by the maximum settlement rate (as adjusted in the manner described herein) and the threshold appreciation price is equal to $100 divided by the minimum settlement rate (as adjusted in the manner described herein).

Whenever the terms of the purchase contracts require us to calculate the daily VWAP per share of our Common Stock over a span of multiple days, our board of directors will make appropriate adjustments in good faith (including, without limitation, to the applicable market value, the early settlement rate or the fundamental change early settlement rate (as the case may be)) to account for any adjustments to the fixed settlement rates (as the case may be) that become effective, or any event that would require such an adjustment if the record date, ex-date, effective date or expiration date (as the case may be) of such event occurs, during the relevant period used to calculate such prices or values (as the case may be).

If:

• the record date for a dividend or distribution on shares of our Common Stock occurs after the end of the 20 consecutive trading day period used for calculating the applicable market value and before the purchase contract settlement date; and

• that dividend or distribution would have resulted in an adjustment of the number of shares issuable to the holders of the purchase contracts had such record date occurred on or before the last trading day of such 20-trading day period,

then we will deem the holders of the purchase contracts to be holders of record of our Common Stock for purposes of that dividend or distribution. In this case, the holders of the purchase contracts would receive the dividend or distribution on our Common Stock together with the number of shares of our Common Stock issuable upon settlement of the purchase contracts.

Recapitalizations, Reclassifications and Changes of Our Common Stock

In the event of:

• any consolidation or merger of us with or into another person;

• any sale, transfer, lease or conveyance to another person of all or substantially all of our property and assets;

• any reclassification of our Common Stock into securities (other than a share split or share combination), including securities other than our Common Stock; or

• any statutory exchange of our securities with another person (other than in connection with a consolidation or merger),

in each case, as a result of which our Common Stock would be converted into, or exchanged for, stock, other securities or other property or assets (including cash or any combination thereof) (each, a “reorganization event”), each purchase contract outstanding immediately prior to such reorganization event shall, without the consent of the holders of the purchase contracts, become a contract to purchase the kind of stock, other securities or other property or assets (including cash or any combination thereof) that a holder of our Common Stock would have been entitled to receive in connection with such reorganization event (such stock, other securities or other property or assets (including cash or any combination thereof), the “exchange property”, with each “unit of exchange property” meaning the kind and amount of exchange property that a holder of one share of our Common Stock would have received in such reorganization event) and, prior to or at the effective time of such reorganization event, we or the successor or purchasing person, as the case may be, shall execute with the purchase contract agent a supplemental agreement pursuant to the purchase contract agreement and the purchase contracts to provide for such change in the right to settle the purchase contracts.

If the transaction causes our Common Stock to be converted into, or exchanged for, the right to receive more than a single type of consideration (determined based in part upon any form of stockholder election), the exchange property underlying the purchase contracts will be deemed to be the weighted average of the types and amounts of consideration actually received by the holders of our Common Stock in such reorganization event.

The number of units of exchange property we will deliver upon the settlement of each purchase contract following the effective date of such reorganization event will be determined as if references to our Common Stock deliverable upon settlement of the purchase contracts on the purchase contract settlement date, early settlement date or fundamental change early settlement date, as the case may be, were to units of exchange property (without interest thereon and without any right to dividends or distributions thereon which have a record date prior to the date on which holders of the purchase contracts become holders of record of the underlying shares of our Common Stock). For the purpose of determining which bullet of the definition of settlement rate in the second paragraph under “-Delivery of Common Stock” will apply upon settlement of each purchase contract, and for the purpose of calculating the settlement rate if the second bullet is applicable, the value of a unit of exchange property will be determined in good faith by our board of directors (which determination will be final), except that if a unit of exchange property includes Common Stock or American Depositary Receipts, or “ADRs”, that are traded on a U.S. national securities exchange, the value of such Common Stock or ADRs will be the average over the 20 consecutive trading day period used for calculating the applicable market value of the volume-weighted average prices for such Common Stock or ADRs, as displayed on the applicable Bloomberg screen (as determined in good faith by our board of directors (which determination will be final)); or, if such price is not available, the average market value per share of such

Common Stock or ADRs over such period as determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained by us for this purpose. The provisions of this paragraph will apply to successive reorganization events, and the provisions summarized under “-Anti-dilution Adjustments to the Fixed Settlement Rates” will apply to any shares of common equity or ADRs of us or any successor received by the holders of shares of our Common Stock in any such reorganization event. We (or any successor to us) will, as soon as reasonably practicable (but in any event within five calendar days) after the occurrence of any reorganization event provide written notice to the holders of the purchase contracts of such occurrence and of the kind and amount of cash, securities or other property that constitute the exchange property. Failure to deliver such notice will not affect the operation of the provisions described in this section.

It is possible that certain consolidations, mergers, combinations or other transactions could result in tax gains or losses to the holders either as a result of the transaction or the conversion thereafter. Holders are encouraged to consult with their own tax advisors regarding the tax consequences of the ownership, disposition and settlement of the purchase contracts.

Fractional Shares

No fractional shares of our Common Stock will be issued to holders upon settlement of the purchase contracts. In lieu of fractional shares otherwise issuable, holders will be entitled to receive an amount in cash equal to the fraction of a share of our Common Stock, calculated on an aggregate basis in respect of the purchase contracts being settled (provided that, so long as the Equity Units are in global form, we may elect to aggregate Equity Units for purposes of these calculations on any basis permitted by the applicable procedures of DTC), multiplied by the daily VWAP of our Common Stock on the trading day immediately preceding the purchase contract settlement date, early settlement date or fundamental change early settlement date, as the case may be.

Legal Holidays

In any case where the purchase contract settlement date, early settlement date or fundamental change early settlement date, as the case may be, shall not be a business day, notwithstanding any term to the contrary in the purchase contract agreement or purchase contract, the settlement of the purchase contracts shall not be effected on such date, but instead shall be effected on the next succeeding business day with the same force and effect as if made on such settlement date, and no interest or other amounts shall accrue or be payable by us or to any holder in respect of such delay.

Consequences of Bankruptcy

Pursuant to the terms of the purchase contract agreement, the purchase contract settlement date for each purchase contract, whether held separately or as part of an Equity Unit, will automatically accelerate upon the occurrence of specified events of bankruptcy, insolvency or reorganization with respect to us. Pursuant to the terms of the purchase contract agreement, upon acceleration, holders will be entitled under the terms of the purchase contracts to receive a number of shares of our Common Stock per purchase contract equal to the maximum settlement rate in effect immediately prior to such acceleration (regardless of the market value of our Common Stock at that time). However, a bankruptcy court may prevent us from delivering our Common Stock in settlement of the accelerated purchase contracts. In such event, a holder would have a damage claim against us for the value of the Common Stock that we would have otherwise been required to deliver upon settlement of the purchase contracts. Any such damage claim that holders have against us following such acceleration will rank pari passu with the claims of holders of our Common Stock in the relevant bankruptcy proceeding. As such, to the extent we fail to deliver Common Stock to the holder upon such an acceleration, the holder will only be able to recover damages to the extent holders of our Common Stock receive any recovery.

Modification

The purchase contract agreement contains provisions permitting us and the purchase contract agent to modify the purchase contract agreement or the purchase contracts without the consent of the holders of purchase contracts (whether held separately or as a component of Equity Units) for any of the following purposes:

• to evidence the succession of another person to us, and the assumption by any such successor of the covenants and obligations of ours in the purchase contract agreement and the units and separate purchase contracts, if any;

• to add to the covenants for the benefit of holders of purchase contracts or to surrender any of our rights or powers under the agreement;

• to evidence and provide for the acceptance of appointment of a successor purchase contract agent;

• upon the occurrence of a reorganization event, solely (i) to provide that each purchase contract will become a contract to purchase exchange property and (ii) to effect the related changes to the terms of the purchase contracts, in each case, as required by the applicable provisions of the purchase contract agreement;

• to conform the provisions of the purchase contract agreement to the “Description of the Purchase Contracts” and “Description of the Equity Units” sections in the preliminary prospectus supplement which forms a part of the registration statement on which the Equity Units are registered, as supplemented by the related pricing term sheet;

• to cure any ambiguity or manifest error, to correct or supplement any provisions that may be inconsistent or defective; and

• to make any other provisions with respect to such matters or questions, so long as such action does not adversely affect the interest of the holders in any material respect.

The purchase contract agreement contains provisions permitting us and the purchase contract agent, with the consent of the holders of not less than a majority of the purchase contracts at the time outstanding, to modify the terms of the purchase contracts or the purchase contract agreement. However, no such modification may, without the consent of the holder of each outstanding purchase contract affected by the modification,

• reduce the number of shares of Common Stock deliverable upon settlement of the purchase contract (except to the extent expressly required pursuant to the anti-dilution adjustments);

• change the purchase contract settlement date, or adversely modify the early settlement right or the fundamental change early settlement right; or

• reduce the above-stated percentage of outstanding purchase contracts the consent of the holders of which is required for the modification or amendment of the provisions of the purchase contracts or the purchase contract agreement.

In executing any modification, the purchase contract agent shall be entitled to receive an opinion of counsel and an officer’s certificate stating that such modification is authorized or permitted under the terms of the purchase contract agreement.

Consolidation, Merger, Sale or Conveyance

Under the purchase contract agreement, we are permitted to consolidate with or merge with or into another company. We are also permitted to sell, assign, transfer, lease or convey all or substantially all of our assets to another company. However, if we take any of these actions, we must meet the following conditions:

• the successor entity to such consolidation or merger, or the entity which acquires all or substantially all of our assets, shall expressly assume all of our obligations under the purchase contracts and the purchase contract agreement;

• the successor entity to such consolidation or merger, or the entity which acquires all or substantially all of our assets, shall be a corporation organized and existing under the laws of the United States or any state thereof or the District of Columbia; and

• immediately after the merger, consolidation, sale, assignment, transfer, lease or conveyance, no default has occurred and is continuing under the purchase contracts or the purchase contract agreement.

Reservation of Common Stock

We will at all times reserve and keep available out of our authorized and unissued Common Stock, solely for issuance upon settlement of the purchase contracts, the number of shares of Common Stock that would be issuable upon the settlement of all purchase contracts then outstanding, assuming settlement at the maximum settlement rate.

Governing Law

The purchase contract agreement, the Equity Units and the purchase contracts is governed by, and construed in accordance with, the laws of the State of New York.

Information Concerning the Purchase Contract Agent

The Bank of New York Mellon Trust Company, N.A. is the purchase contract agent. The purchase contract agent acts as the agent for the holders of Equity Units and separate purchase contracts from time to time. The purchase contract agreement does not obligate the purchase contract agent to exercise any discretionary actions in connection with a default under the terms of the purchase contracts or the purchase contract agreement.

The purchase contract agreement contains provisions limiting the liability of the purchase contract agent. The purchase contract agreement contains provisions under which the purchase contract agent may resign or be replaced. This resignation or replacement would be effective upon the acceptance of appointment by a successor purchase contract agent.

We maintain banking relationships in the ordinary course of business with the purchase contract agent and its affiliates.

Calculations in Respect of Purchase Contracts

We will be responsible for making all calculations called for under the Equity Units and any separate purchase contracts. The purchase contract agent will have no obligation to make, review or verify any such calculations. All such calculations made by us will be made in good faith and, absent manifest error, will be final and binding on the purchase contract agent and the holders of the Equity Units and any separate purchase contracts. We will provide a schedule of such calculations to the purchase contract agent and the purchase contract agent will be entitled to conclusively rely upon the accuracy of such calculations without independent verification.

Description of the U.S. Treasury Strips Components

The U.S. treasury strips underlying the Equity Units are held by the custodian as agent for the holders of the Equity Units and are subject to the terms of a custodial agreement between the custodian and purchase contract agent. The following summary contains a description of all of the material terms of the custodial agreement but is not complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of the custodial agreement, including the definitions in the custodial agreement of certain terms. We refer you to the custodial agreement which is incorporated by reference to this Annual Report on Form 10-K.

Each U.S. treasury strips component will initially form a part of an Equity Unit. On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, the holder will have the right to separate 48,000 Equity Units (or any integral multiples thereof), and withdraw the U.S. treasury strips underlying those Equity Units. Following such separation, U.S. treasury strips may be transferred separately from purchase contracts.

Payments of U.S. Treasury Strips

The U.S. treasury strips are held by the custodian as agent for the holders of the Equity Units. The custodian will, upon instructions from the purchase contract agent, forward to each holder of Equity Units the amount it receives from the U.S. government in respect of each U.S. treasury strip underlying the Equity Units owned by such holder

on the business day immediately following the date such U.S. treasury strip matures on February 15, May 15, August 15 and November 15 of each year, with such payments commencing on, and including, August 17, 2020, and ending on, and including, August 16, 2023. We expect that the amount payable per Equity Unit per full quarter as described in the immediately preceding sentence will be equal to $1.3750, which represents an annual rate of return on the stated amount per Equity Unit of 5.50%. The amount payable per Equity Unit on August 17, 2020 was equal to $0.6875. These payments will consist of the pro rata amount of all amounts received by the custodian in respect of the U.S. treasury strips. So long as the Equity Units remain in the form of one or more book-entry, global Equity Unit certificates as described in “-Book-Entry Procedures and Settlement” below, the record date will be the business day prior to the relevant payment date. If the Equity Units do not remain in the form of one or more book-entry, global Equity Unit certificates, the relevant record date will be the fifteenth day (whether or not a business day) prior to the relevant payment date.

We have no obligation, responsibility or liability with respect to the purchase of the U.S. treasury strips and their delivery into the custody of the custodian, the performance or non-performance of the duties of the custodian or any payment of the U.S. treasury strips components. Goldman Sachs & Co. LLC has purchased the U.S. treasury strips to be sold to the purchasers of the Equity Units and delivered to the custodian, The Bank of New York Mellon Trust Company, N.A.

Each Equity Unit will initially evidence its holder’s 1/48,000th beneficial ownership interest in the following U.S. treasury strips, which will constitute one U.S. treasury strips component:

Maturity	Face Amount			CUSIP
August 15, 2020		$	33,000		912803AU7
November 15, 2020		$	66,000		912820WZ6
February 15, 2021		$	66,000		912803AV5
May 15, 2021		$	66,000		912803AW3
August 15, 2021		$	66,000		912821AG0
November 15, 2021		$	66,000		912820ZH3
February 15, 2022		$	66,000		912833LG3
May 15, 2022		$	66,000		912821BZ7
August 15, 2022		$	66,000		912820RU3
November 15, 2022		$	66,000		912820SH1
February 15, 2023		$	66,000		912820B30
May 15, 2023		$	66,000		912820F36
August 15, 2023		$	66,000		912820G84

Role of Custodian

The custodian is the agent of the holders of the Equity Units evidencing the U.S. treasury strips and is not a trustee, and no trust was intended to be created or was created by the terms of the custodial agreement. The custodian has no managerial role nor any discretion with respect to the U.S. treasury strips and has no right to deal with the U.S. treasury strips except as specifically provided in the custodial agreement. The custodian agrees to hold the U.S. treasury strips and exercise the due care of a professional custodian for hire. Under the custodial agreement, the custodian is required to remit all payments received from the U.S. government in respect of the U.S. treasury strips to the holders of the Equity Units without making any deduction as instructed by the purchase contract agent.

Ownership of U.S. Treasury Strips

The U.S. treasury strips will at all times be the sole and exclusive property of the holders of the Equity Units. The custodian may not transfer, assign, pledge, set off or otherwise dispose of any of the U.S. treasury strips or any interests therein, except as expressly permitted by the provisions of the custodial agreement.

Withdrawal of U.S. Treasury Strips

On any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the Equity Units to, but excluding, the second scheduled trading day immediately preceding August 16, 2023, a holder of 48,000 Equity Units (or any integral multiple thereof) will have the right to separate such Equity Units and withdraw the U.S. treasury strips underlying those Equity Units. To withdraw the U.S. treasury strips underlying Equity Units, holders must follow the procedures outlined under the above caption “Description of the Equity Units-Separating and Recreating Equity Units-Separating Equity Units.” The purchase contract agent will then (i) cancel the Equity Units and deliver to the holder the purchase contracts evidenced by the Equity Units and (ii) instruct the custodian to deliver to the holder such holder’s U.S. treasury strips. Any administrative fees and expenses related to withdrawing the U.S. treasury strips evidenced by the Equity Units that are payable to the purchase contract agent or the custodian will be at the expense of the holder of Equity Units requesting withdrawal. To recreate the Equity Units, holders must follow the procedures outlined under the above caption “Description of the Equity Units-Separating and Recreating Equity Units-Recreation of Equity Units.” Because each Equity Unit evidences a 1/48,000th beneficial ownership interest in specified U.S. treasury strips, any separation or recreation of Equity Units may be made only in integral multiples of 48,000 Equity Units.

Certain Other Provisions of the Custodial Agreement

Delivery of U.S. Treasury Strips

Payments of the U.S. treasury strips components will be made by the custodian to the depositary as long as the Equity Units remain in book-entry form. In addition, if the Equity Units do not remain in book-entry form, payments may be made, at the option of the custodian, by check mailed to the address of the person entitled to the payments as shown on the Equity Unit register.

If the purchase contract settlement date is accelerated, U.S. treasury strips will be delivered by the custodian upon presentation and surrender of the Equity Unit certificates evidencing the related Equity Units at the office of the purchase contract agent or, in the case of book-entry Equity Units, upon presentation and surrender of the Equity Units in accordance with the procedures of the depositary. Following such acceleration and delivery, the custodian will sell (or, at the expense of holders, retain the services of a broker dealer that will sell) such U.S. treasury strips, and the custodian will distribute the net cash proceeds of such sale (less any expenses incurred by the custodian in connection with such sale) on a pro rata basis to holders of Equity Units (or in accordance with the procedures of the depositary in the case of global Equity Units). Until the Equity Unit certificate is presented and surrendered or the holder provides satisfactory evidence that the Equity Unit certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the purchase contract agent, the U.S. treasury strips will be held by the custodian for the account of the holder. The custodian will have no obligation to invest or to pay interest on any amounts held by the custodian pending delivery.

Modification

The custodial agreement contains provisions prohibiting the custodian and the purchase contract agent, except under limited circumstances, from modifying or amending the terms of the custodial agreement without the consent of the holder of each outstanding Equity Unit affected by the modification or amendment.

Governing Law

The custodial agreement is governed by, and construed in accordance with, the laws of the State of New York.

Information Concerning the Custodian

The Bank of New York Mellon Trust Company, N.A., whose designated office is located at 400 South Hope Street, Suite 500, Los Angeles, CA 90071, acts as the custodian of the U.S. treasury strips on behalf of the holders of Equity Units from time to time.

The custodial agreement does not obligate the custodian to perform any discretionary actions in connection with the terms of the Equity Units or the custodial agreement. The custodial agreement also contains provisions limiting the liability of the custodian and the circumstances under which the custodian may resign or be replaced. No such resignation or replacement will be effective until a successor custodian is appointed.

We maintain banking relationships in the ordinary course of business with the custodian and its affiliates.

Book Entry Procedures and Settlement

Except in the limited circumstances described herein, the Equity Units and the purchase contracts are issued in the form of one or more global Equity Unit certificates and global purchase contract certificates, respectively, held by the purchase contract agent, as custodian for, and registered in the name of, The Depository Trust Company (“DTC”), as depositary, or its nominee.

The depositary has advised us as follows: The depositary is a limited-purpose trust company organized under the Banking Law of the State of New York, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to Section 17A of the U.S. Securities Exchange Act of 1934 (the “Exchange Act”). The depositary was created to hold securities of its participants (defined below) and to facilitate the clearance and settlement of transactions among its participants in such securities through electronic book-entry changes in accounts of the participants, thereby eliminating the need for physical movement of certificates. The depositary’s participants include securities brokers and dealers, banks, trust companies, clearing corporations and some other organizations, some of whom (and/or their representatives) own the depositary. Access to the depositary’s book-entry system is also available to others, such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly.

No Equity Unit represented by global Equity Unit certificates and no purchase contract represented by global purchase contract certificates may be exchanged in whole or in part for definitive Equity Units or purchase contracts, as the case may be, and no transfer of global Equity Unit certificates and global purchase contract certificates in whole or in part may be registered, in the name of any person other than the depositary or any nominee of the depositary unless:

• the depositary has notified the purchase contract agent that it is unwilling or unable to continue as depositary for such global Equity Unit certificates or global purchase contract certificates, as the case may be, or has ceased to be qualified to act as such as required by the purchase contract agreement;

• there shall have occurred and be continuing a default by us in respect of our obligations under the purchase contract agreement; or

• the beneficial holder of Equity Units elects to withdraw the U.S. treasury strips evidenced by one or more of its Equity Units and elects to hold the purchase contracts in definitive form.

All Equity Units and purchase contracts represented by one or more global Equity Unit certificates and global purchase contract certificates, respectively, or any portion thereof are registered in such names as the depositary may have directed.

The laws of some jurisdictions require that some purchasers of Equity Units take physical delivery of the Equity Units in definitive form. These laws may impair a holder’s ability to transfer beneficial interests in Equity Units so long as they are represented by global Equity Unit certificates.

As long as the depositary (or its nominee) is the registered owner of the global Equity Unit certificates and the global purchase contract certificates, the depositary (or its nominee) will be considered the sole owner and holder of the global Equity Unit certificates, the global purchase contract certificates and all Equity Units and purchase contracts represented thereby for all purposes under the Equity Units and purchase contracts and the purchase contract agreement. Except in the limited circumstances referred to above, owners of beneficial interests in global Equity Unit certificates and owners of beneficial interests in global purchase contract certificates:

• are not be entitled to have the global purchase contract certificates or the purchase contracts represented thereby registered in their respective names;

• will not receive or be entitled to receive physical delivery of Equity Unit certificates or purchase contract certificates, as the case may be, in exchange therefor; and

• are not be considered to be owners or holders of global Equity Unit certificates or any Equity Units represented thereby or global purchase contract certificates or any purchase contracts represented thereby, for any purpose under the Equity Units, the purchase contracts or the purchase contract agreement.

All transfers and deliveries of shares of our Common Stock (and any cash amount paid by us in lieu of fractional shares) issued on settlement of the purchase contracts evidenced by the Equity Units in global form and all transfers and deliveries of the U.S. treasury strips evidenced by the Equity Units in global form will be made to the depositary (or its nominee) as the holder thereof. All transfers and deliveries of shares of our Common Stock (and any cash amount paid by us in lieu of fractional shares) pursuant to the purchase contracts represented by the global purchase contract certificates will be made by the purchase contract agent to the depositary (or its nominee) as the holder thereof. Cash payments in respect of the U.S. treasury strips component of Equity Units in global form will be made by the custodian, at the direction of the purchase contract agent, to the depositary (or its nominee) as the holder of such Equity Units.

Ownership of beneficial interests in the global Equity Unit certificates and global purchase contract certificates is limited to participants or persons that may hold beneficial interests through institutions that have accounts with the depositary or its nominee, which we refer to as participants. Ownership of beneficial interests in global Equity Unit certificates and global purchase contract certificates will be shown only on, and the transfer of those ownership interests will be effected only through, records maintained by the depositary or its nominee (with respect to participants’ interests) or any such participant (with respect to interests of persons held by such participants on their behalf). Procedures for settlement of purchase contracts on the purchase contract settlement date or upon early settlement for holders who hold in book-entry form will be governed by arrangements among the depositary, participants and persons that may hold beneficial interests through participants designed to permit such settlement without the physical movement of certificates. Payments, transfers, deliveries, exchanges and other matters relating to beneficial interests in global Equity Unit certificates may be subject to various policies and procedures adopted by the depositary from time to time. None of PG&E Corporation, the purchase contract agent or the custodian or any of their respective agents will have any responsibility or liability for any aspect of the depositary’s or any participant’s records relating to, or for payments made on account of, beneficial interests in global Equity Unit certificates or global purchase contract certificates, or for maintaining, supervising or reviewing any of the depositary’s records or any participant’s records relating to such beneficial ownership interests.

Notices

So long as the global securities are held on behalf of DTC or any other clearing system, notices to holders of securities represented by a beneficial interest in the global securities may be given by delivery of the relevant notice to DTC or the alternative clearing system, as the case may be.

EX-4.51(B)

EXHIBIT 4.51(b)

DESCRIPTION OF PACIFIC GAS AND ELECTRIC COMPANY’S

SECURITIES REGISTERED UNDER

SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

Description of Preferred Stock

The following description of Pacific Gas and Electric Company’s (the “Utility”) preferred stock is only a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to applicable law, our Restated Articles of Incorporation effective as of June 22, 2020 (the “Articles of Incorporation”) and Bylaws amended and restated as of May 20, 2021 (the “Bylaws”), each of which is filed as an exhibit to this Annual Report on Form 10-K and is incorporated by reference herein. We encourage you to read the Articles of Incorporation and the Bylaws for additional information.

In this section, references to “we,” “our,” “ours” and “us” refer only to the Utility and not to any of its direct or indirect parents, subsidiaries or affiliates except as expressly provided.

General

Our Articles of Incorporation authorize the issuance of 800,000,000 shares of common stock with a par value of $5 per share, 75,000,000 shares of first preferred stock with a par value of $25 per share (the “First Preferred Stock”), and 10,000,000 of $100 first preferred stock, cumulative, with a par value of $100 per share (the “$100 First Preferred Stock” and, together with the First Preferred Stock, the “Preferred Stock”).

All outstanding shares of our common stock are owned by PG&E Corporation. There are no shares of $100 First Preferred Stock outstanding. First Preferred Stock is issued and outstanding in the following series:

•5% series A redeemable (“5% First Preferred Series A Stock”)

•5% redeemable (“5% First Preferred Stock”)

•4.80% redeemable (“4.8% First Preferred Stock”)

•4.50% redeemable (“4.5% First Preferred Stock”)

•4.36% series A redeemable (“4.36% First Preferred Series A Stock”)

•6% nonredeemable (“6% Nonredeemable First Preferred Stock”)

•5.50% nonredeemable (“5.5% Nonredeemable First Preferred Stock”)

•5% nonredeemable (“5% Nonredeemable First Preferred Stock”)

As of December 31, 2021, the Utility’s First Preferred Stock outstanding included:

•4,211,661 shares of 6% Nonredeemable First Preferred Stock;

•1,173,163 shares of 5.5% Nonredeemable First Preferred Stock;

•400,000 shares of 5% Nonredeemable First Preferred Stock;

•1,778,172 shares of 5% First Preferred Series A Stock;

•934,322 shares of 5% First Preferred Stock;

•793,031 shares of 4.8% First Preferred Stock;

•611,142 shares of 4.5% First Preferred Stock; and

•418,291 shares of 4.36% First Preferred Series A Stock.

Under the Articles of Incorporation, the Board of Directors of the Utility is authorized without further shareholder action to provide for the issuance of Preferred Stock up to the amounts authorized by the Articles of Incorporation, in one or more series, with such rights, preferences, privileges and restrictions as shall be stated and expressed in the resolution or resolutions providing for the issue of such Preferred Stock, or series thereof, adopted, at any time or from time to time, by the Board of Directors.

Voting Rights

Except as otherwise provided by law, holders of our Preferred Stock have voting rights on the basis of one vote per share on each matter submitted to a vote at a meeting of shareholders. Our shareholders may not cumulate votes in elections of directors. As a result, the holders of our Preferred Stock entitled to exercise more than 50% of the voting rights in an election of directors can elect all of the directors to be elected if they choose to do so. In such event, the holders of the remaining Preferred Stock voting for the election of directors will not be able to elect any persons to the Board of Directors.

Dividend Rights

The owners and holders of shares of Preferred Stock, when issued as fully paid, are entitled to receive, from the date of issue of such share, out of funds legally available therefor, cumulative preferential dividends, when and as declared by the Board of Directors, at the following rates upon the par value of their respective shares, and not more:

•5% per year upon the 5% First Preferred Series A Stock, 5% First Preferred Stock and 5% Nonredeemable First Preferred Stock

•4.8% per year upon the 4.8% First Preferred Stock

•4.5% per year upon the 4.5% First Preferred Stock

•4.36% per year upon the 4.36% First Preferred Stock

•6% per year upon the 6% Nonredeemable First Preferred Stock

•5.5% per year upon the 5.5% Nonredeemable First Preferred Stock

Such dividends shall be declared and shall be either paid or set apart for payment before any dividend upon the shares of common stock shall be either declared or paid. All shares of Preferred Stock rank equally in priority with regard to preference in dividend rights, except that shares of different classes or different series thereof may differ as to the amounts of dividends to which they are entitled.

Liquidation Rights

Upon the liquidation or dissolution of the Utility at any time and in any manner, the owners and holders of Preferred Stock issued as fully paid will be entitled to receive an amount equal to the par value of such shares plus an amount equal to all accumulated and unpaid dividends thereon to and including the date fixed for such distribution or payment before any amount shall be paid to the holders of the Utility’s common stock. All shares of Preferred Stock rank equally in priority with regard to preference in liquidation rights, except that shares of different classes or different series thereof may differ as to the amounts of liquidation payments to which they are entitled. All shares of Preferred Stock rank senior to common stock with regard to liquidation rights.

If any share or shares of Preferred Stock shall at any time be issued as only partly paid, the owners and holders of such partly paid share or shares shall have the right to receive dividends and to share in the assets of the Utility upon its liquidation or dissolution in all respects like the owners and holders of fully paid shares of Preferred

Stock, except that such right shall be only in proportion to the amount paid on account of the subscription price for which such partly paid share or shares shall have been issued.

Conversion, Redemption and Preemptive Rights

None of the 6% Nonredeemable First Preferred Stock, 5.5% Nonredeemable First Preferred Stock and 5% Nonredeemable First Preferred Stock is subject to redemption.

The remaining outstanding series of First Preferred Stock, and any Preferred Stock issued in the future, may be redeemed at the Utility’s option, at any time or from time to time, at the redemption price fixed for such series of Preferred Stock together with accumulated and unpaid dividends at the rate fixed therefor to and including the date fixed for redemption. If less than all the outstanding shares of any such series are to be redeemed, the shares to be redeemed shall be determined pro rata or by lot in such manner as the Board of Directors may determine. There is no restriction on the repurchase or redemption of Preferred Stock by the Utility while there is any arrearage in the payment of dividends or sinking fund payments.

Unless the certificate of determination for any series of Preferred Stock shall otherwise provide, notice of every redemption shall be published in a newspaper of general circulation in the City and County of San Francisco, State of California, and in a newspaper of general circulation in the Borough of Manhattan, City and State of New York, at least once in each of two (2) successive weeks, commencing not earlier than sixty (60) nor later than thirty (30) days before the date fixed for redemption; successive publications need not be made in the same newspaper. A copy of such notice shall be mailed within the same period of time to each holder of record, as of the record date, of the shares to be redeemed, but the failure to mail such notice to any shareholder shall not invalidate the redemption of such shares.

From and after the date fixed for redemption, unless default be made by the Utility in paying the amount due upon redemption, dividends on the shares called for redemption shall cease to accrue, and such shares shall be deemed to be redeemed and shall be no longer outstanding, and the holders thereof shall cease to be shareholders with respect to such shares and shall have no rights with respect thereto except the right to receive from the Utility upon surrender of their certificates the amount payable with respect thereto upon redemption without interest.

None of the Preferred Stock has preemptive rights or conversion rights.

Non-Assessability

Shares of Preferred Stock, the subscription price of which shall have been paid in full, whether such price be par or more or less than par, shall be issued as fully paid shares and shall never be subject to any call or assessment for any purpose whatever. Shares of Preferred Stock, only a part of the subscription price of which shall have been paid, shall be subject to calls for the unpaid balance of the subscription price thereof. But no call made on partly paid Preferred Stock or partly paid common stock shall be recoverable by action or be enforceable otherwise than by sale or forfeiture of delinquent stock in accordance with the applicable provisions of the Corporations Code of California.

If at any time, whether by virtue of any amendment of the Articles of Incorporation or any amendment or change of the law of the State of California relating to corporations or otherwise, any assessment shall, in any event whatsoever, be levied and collected on any subscribed and issued shares of Preferred Stock after the subscription price thereof shall have been paid in full, the rights of the owners and holders thereof to receive dividends and their rights to share in the assets upon the liquidation or dissolution of the Utility shall, immediately upon the payment of such assessment and by virtue thereof, be increased in the same ratio as the total amount of the assessment or assessments so levied and collected shall bear to the par value of such shares of Preferred Stock.

Listing

The outstanding series of First Preferred Stock are listed on the NYSE American as follows:

•5% First Preferred Series A Stock is listed under the trading symbol PCG-PE

•5% First Preferred Stock is listed under trading symbol PCG-PD

•4.8% First Preferred Stock is listed under trading symbol PCG-PG

•4.5% First Preferred Stock is listed under trading symbol PCG-PH

•4.36% First Preferred Series A Stock is listed under trading symbol PCG-PI

•6% Nonredeemable First Preferred Stock is listed under trading symbol PCG-PA

•5.5% Nonredeemable First Preferred Stock is listed under trading symbol PCG-PB

•5% Nonredeemable First Preferred Stock is listed under trading symbol PCG-PC

Transfer Agent

The transfer agent for our Preferred Stock is EQ Shareowner Services.

EX-10.29

EXHIBIT 10.29

AMENDMENT NO. 2 TO CREDIT AGREEMENT

This AMENDMENT NO. 2, dated as of December 31, 2021 (this “Amendment”), is entered into by and among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), the Consenting Lenders (as defined below), the other Lenders (as defined below) party hereto, and JPMORGAN CHASE BANK, N.A. (“JPMCB”), as administrative agent (in such capacity and including any successors in such capacity, the “Administrative Agent”).

RECITALS:

WHEREAS, reference is hereby made to the Term Loan Credit Agreement, dated as of July 1, 2020, among the Borrower, the lenders party thereto from time to time, the Administrative Agent and the other parties thereto (as amended by that certain Amendment No. 1 to Credit Agreement dated as of October 29, 2021 (the “Amendment No. 1”), the “Credit Agreement”, capitalized terms used (including in the preamble and recitals hereto) but not defined herein shall have the meanings assigned to such terms in the Credit Agreement (as amended hereby));

WHEREAS, the Borrower, the Lenders party thereto and the Administrative Agent previously entered into the Amendment No. 1 pursuant to which the Lenders party thereto agreed to extend the maturity date of the Loans held by such Lenders, which Loans are the 18-Month Tranche Loans (Tranche A);

WHEREAS, each Consenting Lender holding 18-Month Tranche Loans (Tranche B) (the “Existing Loans”) immediately prior to the Amendment No. 2 Effective Date that executes and delivers an executed counterpart to this Amendment agrees to the terms of this Amendment upon the effectiveness of this Amendment on the Amendment No. 2 Effective Date (such lenders, the “Consenting Lenders”), whereby the maturity date of the Existing Loans held by the Consenting Lenders will be extended from January 1, 2022 to October 1, 2022 (the Existing Loans so extended, the “Extended Loans”);

WHEREAS, the Required Lenders party hereto agree to the other changes set forth herein;

WHEREAS, JPMCB (or an Affiliate thereof) is acting as a joint lead arranger and bookrunner (in such capacity, the “Left Lead Arranger”) in respect of this Amendment and Barclays Bank PLC, BofA Securities, Inc., Goldman Sachs Bank USA, Wells Fargo Securities, LLC and Citibank, N.A. are acting as joint lead arrangers and bookrunners (in such capacities, together with the Left Lead Arranger, the “Lead Arrangers”) in respect of this Amendment; and

WHEREAS, this Amendment is an amendment made with the consent of the Consenting Lenders, the Required Lenders, the Borrower and the Administrative Agent pursuant to Section 10.1 of the Credit Agreement.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration (the receipt and sufficiency of which is hereby acknowledged), the parties hereto hereby agree as follows:

A.Amendments to Credit Agreement.

(i)On the Amendment No. 2 Effective Date (as defined below), the Credit Agreement is hereby amended to:

(A)Amend Section 1.1 of the Credit Agreement by adding the following defined terms in correct alphabetical order:

“Amendment No. 2”: that certain Amendment No. 2 to Credit Agreement, dated as of the Amendment No. 2 Effective Date, among the Borrower, each Lender party thereto, and JPMorgan Chase Bank, N.A., as administrative agent.

“Amendment No. 2 Effective Date”: December 31, 2021.

(B)Amend and restate the definition of “18-Month Tranche Maturity Date” contained in Section 1.1 of the Credit Agreement in its entirety as follows:

“18-Month Tranche Maturity Date”: October 1, 2022.

(C)Amend and restate Section 2.1(b) of the Credit Agreement in its entirety as follows:

(b)    Subject to the terms and conditions set forth herein, each 18-Month Tranche Lender (severally and not jointly) agrees to make a term loan (the “18-Month Tranche Loans”) to the Borrower in Dollars on the Effective Date in an aggregate amount equal to the amount of such 18-Month Tranche Lender’s 18-Month Tranche Commitment. Loans under the 18-Month Tranche may be ABR Loans or Eurodollar Rate Loans, as further provided herein. 18-Month Tranche Loans borrowed under this Section 2.1(b) and paid or prepaid may not be reborrowed. As of the Amendment No. 1 Effective Date, a portion of the 18-Month Tranche Loans in an aggregate amount of $1,315,735,897.44 (the “18-Month Tranche Loans (Tranche A)”) shall have an 18-Month Tranche Maturity Date of October 1, 2022 and a portion of the 18-Month Tranche Loans in an aggregate amount of $184,264,102.56 (the “18-Month Tranche Loans (Tranche B)”) shall have an 18-Month Tranche Maturity Date of January 1, 2022. As of the Amendment No. 2 Effective Date, the 18-Month Tranche Loans (Tranche B) shall have an 18-Month Tranche Maturity Date of October 1, 2022.

(D)Amend Section 2.6 of the Credit Agreement by adding the following as a new clause (d):

(d)    On June 1, 2022, the Borrower agrees to pay to the Administrative Agent, for the account of each Lender that holds any 18-Month Tranche Loans (Tranche B) outstanding on such date, a fee equal to 0.075% of the principal amount of such Loans.

(E)Amend the penultimate paragraph of Section 10.1 of the Credit Agreement by adding the following new parenthetical at the end of clause (iv) thereof:

(for the avoidance of doubt, such replacement shall be effective subject to the conditions in the other clauses set forth in this proviso, regardless of whether such replaced Lender enters into an Assignment and Assumption)

(ii)Effective on January 1, 2022, the Credit Agreement is hereby amended to delete the stricken text (indicated textually in the same manner as the following example: stricken text) and to add the double-underlined text (indicated textually in the same manner as the following example: double-underlined text) as set forth in the pages of the Credit Agreement attached as Exhibit A hereto.

B.Prepayments and Assignments. On or prior to the Amendment No. 2 Effective Date, the Borrower shall prepay $59.26 million in principal amount of the 18-Month Tranche Loans (Tranche B) (as defined in the Credit Agreement prior to giving effect to this Amendment). On the Amendment No. 2 Effective Date and immediately preceding the effectiveness of this Amendment, all Lenders holding the 18-Month Tranche Loans (Tranche B) that are not Consenting Lenders shall be replaced with one or more Consenting Lenders pursuant to the penultimate paragraph of Section 10.1 of the Credit Agreement (as amended hereby) such that immediately after the effectiveness of this Amendment, the allocation of the 18-Month Tranche Loans are as set forth as Schedule 1.1 hereto.

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C.Conditions Precedent. This Amendment shall become effective as of the date first above written when, and only when, each of the following conditions precedent shall have been satisfied or, to the extent permitted under the Credit Agreement, waived (the “Amendment No. 2 Effective Date”):

1.Executed Counterparts. The Administrative Agent shall have received a counterpart to this Amendment duly executed by the Borrower, the Consenting Lenders, the Required Lenders and the Administrative Agent;

2.Organizational Documents; Certificates. The Administrative Agent shall have received (i) a certificate of the Borrower, dated the Amendment No. 2 Effective Date (with a recent short-form good standing certificate of the Borrower), similar to the one delivered pursuant to Section 5.1(f) of the Credit Agreement, with appropriate insertions and attachments and (ii) a certificate of a Responsible Officer, dated the Amendment No. 2 Effective Date, confirming the satisfaction of the conditions precedent set forth in clauses (3) and (4) below;

3.Representations and Warranties. The representations and warranties of the Borrower contained in Section 4 of the Credit Agreement (other than the representations and warranties set forth in Sections 4.2, 4.6(b) and 4.13)shall be true and correct in all material respects immediately prior to and immediately after giving effect to this Amendment; provided that each of such representations and warranties that contains a materiality qualification shall be true and correct on and as of the Amendment No. 2 Effective Date (or, to the extent such representations and warranties specifically relate to an earlier date, such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date);

4.No Default. No Default or Event of Default shall have occurred and be continuing immediately prior to, and immediately after giving effect to, the Amendment No. 2 Effective Date;

5.Fees and Expenses. On or prior to the Amendment No. 2 Effective Date, the Borrower shall have paid all reasonable out-of-pocket costs and expenses of the Administrative Agent and the Lead Arrangers required to be paid or reimbursed by the Borrower in connection with the preparation, negotiation, execution and delivery of this Amendment and related documentation (including, in each case, without limitation, the reasonable fees and disbursements of counsel for the Administrative Agent and the Lead Arrangers with respect thereto);

6.KYC Information. At least three (3) Business Days prior to the Amendment No. 2 Effective Date, the Administrative Agent and each Consenting Lender shall have received all documentation and information relating to the Borrower as is reasonably requested in writing by the Administrative Agent and/or any such Consenting Lender at least ten (10) Business Days prior to the Amendment No. 2 Effective Date that is required by Governmental Authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation. If the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation and the Administrative Agent or any Consenting Lender so request at least five (5) Business Days prior to the Amendment No. 2 Effective Date, then at least three (3) Business Days prior to the Amendment No. 2 Effective Date, the Borrower shall have delivered to the Administrative Agent and/or any such Consenting Lender a Beneficial Ownership Certification in relation to the Borrower.

7.Bond Documents. The Administrative Agent shall have received evidence reasonably satisfactory to it that the Borrower has caused to be delivered to the Trustee under the FMB Indenture the items described in Section IV Extension Procedures for the Bonds of the Thirty-Fourth Series of the Eleventh Supplemental Indenture.

D.Other Terms.

1.Reference to the Effect on the Loan Documents.

(i)As of the Amendment No. 2 Effective Date, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, and each

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reference in the other Loan Documents to the “Credit Agreement” (including, without limitation, by means of words like “thereunder,” “thereof” and words of like import), shall mean and be a reference to the Credit Agreement as amended hereby, and this Amendment and the Credit Agreement shall be read together and construed as a single instrument.

(ii)Except as expressly amended hereby or specifically waived or consented to above, all of the terms and provisions of the Credit Agreement and all other Loan Documents are and shall remain in full force and effect and are hereby ratified and confirmed.

(iii)The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders, the Borrower, the Lead Arrangers or the Administrative Agent under any of the Loan Documents, nor constitute a waiver or amendment of any other provision of any of the Loan Documents or for any purpose except as expressly set forth herein.

(iv)This Amendment is a Loan Document.

2.Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page of (x) this Amendment and/or (y) any document, amendment, approval, consent, information, notice, certificate, request, statement, disclosure or authorization related to this Amendment and/or the transactions contemplated hereby (each an “Ancillary Document”) that is an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record (each, an “Electronic Signature”) transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually executed counterpart of this Amendment or such Ancillary Document, as applicable. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Amendment and/or any Ancillary Document shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be.

3.Ratification. This Amendment shall be effective pursuant to Section 10.1 of the Credit Agreement (and approved and ratified by the Consenting Lenders, the Required Lenders and the Administrative Agent for all purposes under the Loan Documents).

4.Governing Law.THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

5.Section Titles. The section titles contained in this Amendment are and shall be without substantive meaning or content of any kind whatsoever and are not a part of the agreement between the parties hereto, except when used to reference a section.

6.Notices. All communications and notices hereunder shall be given as provided in the Credit Agreement.

7.Severability. The fact that any term or provision of this Amendment is held invalid, illegal or unenforceable as to any person in any situation in any jurisdiction shall not affect the validity, enforceability or legality of the remaining terms or provisions hereof or the validity, enforceability or legality of such offending term or provision in any other situation or jurisdiction or as applied to any person.

8.Successors. The terms of this Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns.

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9.Jurisdiction; Waiver of Jury Trial. The jurisdiction and waiver of right to trial by jury provisions in Section 10.12 and Section 10.15, respectively, of the Credit Agreement are incorporated herein by reference mutatis mutandis.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, each of the undersigned has caused its duly authorized officer to execute and deliver this Amendment as of the date first set forth above.

PACIFIC GAS AND ELECTRIC COMPANY,
as the Borrower

By:    /s/ Margaret K. Becker                        

Name: Margaret K. Becker

Title: Vice President and Treasurer

Signature Page to Amendment No. 2
Pacific Gas and Electric Company

JPMORGAN CHASE BANK, N.A., as Administrative Agent
By:	/s/ Arina Mavilian
Name:    Arina Mavilian
Title: Authorized Signatory

BANK OF AMERICA, N.A., as a Consenting Lender
By:	/s/ Holli Balzer
Name:    Holli Balzer
Title:    Vice President

MIZUHO BANK, LTD., as a Consenting Lender
By:	/s/ Edward Sacks
Name:    Edward Sacks
Title:    Authorized Signatory

BNP PARIBAS, as a Lender
By:	/s/ Denis O’Meara
Name:    Denis O’Meara
Title:    Managing Director

By:	/s/ Francis DeLaney
Name:    Francis DeLaney
Title:    Managing Director

BARCLAYS BANK PLC, as a Lender
By:	/s/ Jake Lam
Name:    Jake Lam
Title:    Assistant Vice President

MUFG UNION BANK, N.A., as a Consenting Lender
By:	/s/ Nietzsche Rodricks
Name:    Nietzsche Rodricks
Title:    Managing Director

WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Consenting Lender
By:	/s/ Gregory R. Gredvig
Name:    Gregory R. Gredvig
Title:    Director

GOLDMAN SACHS BANK USA, as a Consenting Lender
By:	/s/ Dan Martis
Name:    Dan Martis
Title:    Authorized Signatory

BANK OF MONTREAL, CHICAGO BRANCH, as a Consenting Lender
By:	/s/ Darren Thomas
Name:    Darren Thomas
Title:    Director

CITIBANK, N.A., as a Consenting Lender
By:	/s/ Richard Rivera
Name:    Richard Rivera
Title:    Vice President

PERPETUAL PRIVATE CREDIT POOLED FUND, as a Consenting Lender
By:	/s/ Lon Erickson
Name:    Lon Erickson
Title:    Vice President

THORNBURG LIMITED TERM INCOME FUND, as a Consenting Lender
By:	/s/ Lon Erickson
Name:    Lon Erickson
Title:    Vice President

THORNBURG STRATEGIC INCOME FUND, as a Consenting Lender
By:	/s/ Lon Erickson
Name:    Lon Erickson
Title:    Vice President

EXHIBIT A

$3,000,000,000

TERM LOAN CREDIT AGREEMENT

among

PACIFIC GAS AND ELECTRIC COMPANY,
as Borrower,

the Several Lenders from Time to Time Parties Hereto,

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent,

BOFA SECURITIES, INC.,

BARCLAYS BANK PLC,

CITIBANK, N.A.,

and GOLDMAN SACHS BANK USA,
as Co-Syndication Agents,

and

BNP PARIBAS,

CREDIT SUISSE AG, NEW YORK BRANCH,

MIZUHO BANK, LTD.,

MUFG UNION BANK, N.A.,

and WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Co-Documentation Agents

Dated as of July 1, 2020

as amended by Amendment No. 12 to Credit Agreement dated as of October 29December 31, 2021

JPMorgan Chase Bank, N.A.,
BofA Securities, Inc.,
Barclays Bank PLC,
Citibank, N.A.
and Goldman Sachs Bank USA
as Joint Lead Arrangers and
Joint Bookrunners

TABLE OF CONTENTS

Page

SECTION 1.DEFINITIONS    1

1.1Defined Terms    1

1.2Other Definitional Provisions and Interpretative Provisions    30

1.3Divisions    31

1.4Interest Rates; LIBOR Notification    31

SECTION 2.AMOUNT AND TERMS OF THE TERM LOANS    32

2.1Loans    32

2.2Procedures for Borrowing    32

2.3[Reserved]    33

2.4[Reserved]    33

2.5[Reserved]    33

2.6Fees, Etc.    33

2.7Termination of Commitments    33

2.8Prepayments    33

2.9Conversion and Continuation Options    34

2.10Limitations on Eurodollar Tranches    35

2.11Interest Rates and Payment Dates    35

2.12Computation of Interest and Fees    36

2.13Inability to Determine Interest Rate    36

2.14Pro Rata Treatment and Payments; Notes    38

2.15Change of Law    39

2.16Taxes    41

2.17Indemnity    45

2.18Change of Lending Office    45

2.19Replacement of Lenders    46

2.20Defaulting Lenders    46

SECTION 3.[RESERVED]    47

SECTION 4.REPRESENTATIONS AND WARRANTIES    47

4.1Financial Condition    47

4.2No Change    48

4.3Existence; Compliance with Law    48

4.4Power; Authorization; Enforceable Obligations    48

4.5No Legal Bar    49

4.6Litigation    49

4.7No Default    49

4.8Taxes    49

4.9Federal Regulations    50

4.10ERISA    50

4.11Investment Company Act; Other Regulations    50

4.12Use of Proceeds    51

4.13Environmental Matters    51

4.14Regulatory Matters    51

4.15Sanctions; Anti-Corruption    51

4.16Affected Financial Institutions    51

4.17Solvency    51

4.18Disclosure    51

4.19Status of Obligations    52

4.20Ownership of Property    52

SECTION 5.CONDITIONS PRECEDENT    52

5.1Conditions to the Effective Date    52

SECTION 6.AFFIRMATIVE COVENANTS    54

6.1Financial Statements    54

6.2Certificates; Other Information    55

6.3Payment of Taxes.    56

6.4Maintenance of Existence; Compliance    56

6.5Maintenance of Property; Insurance    56

6.6Inspection of Property; Books and Records; Discussions    56

6.7Notices    57

6.8Maintenance of Licenses, etc.    57

6.9Further Assurances    57

SECTION 7.NEGATIVE COVENANTS    58

7.1Indebtedness    58

7.2Consolidated Capitalization Ratio    60

7.3Liens    60

7.4Fundamental Changes    60

7.5Sale and Lease Back Transactions    60

7.6Swap Agreements    61

7.7Amendments to FMB Indenture    61

SECTION 8.EVENTS OF DEFAULT    61

SECTION 9.THE AGENTS    64

9.1Appointment and Authority    64

9.2Delegation of Duties    64

9.3Exculpatory Provisions    64

9.4Reliance by Administrative Agent    65

9.5Notice of Default    66

9.6Non-Reliance on Agents and Other Lenders    66

9.7Indemnification    66

9.8Agent in Its Individual Capacity    67

9.9Successor Agents    67

9.10Documentation Agents and Syndication Agents    68

9.11Administrative Agent May File Proofs of Claim    68

9.12Certain ERISA Matters    69

9.13Erroneous Payment    69

SECTION 10.MISCELLANEOUS    70

10.1Amendments and Waivers    70

10.2Notices    72

10.3No Waiver; Cumulative Remedies    74

10.4Survival of Representations and Warranties    74

10.5Payment of Expenses and Taxes    75

10.6Successors and Assigns; Participations and Assignments.    76

10.7Adjustments; Set off    80

10.8Counterparts; Binding Effect    81

10.9Severability    81

10.10Integration    82

10.11GOVERNING LAW    82

10.12Submission To Jurisdiction; Waivers    82

10.13Acknowledgments    83

10.14Confidentiality    83

10.15WAIVERS OF JURY TRIAL    84

10.16USA Patriot Act; Beneficial Ownership Regulation    84

10.17Judicial Reference    84

10.18No Advisory or Fiduciary Responsibility    84

10.19Acknowledgement Regarding Any Supported QFCs    85

10.20Acknowledgement and Consent to Bail-In of Affected Financial Institutions    85

SCHEDULES:

1.1    Commitments

7.5    Sale and Lease Back Transactions

EXHIBITS:

A    [Reserved]

B    [Reserved]

C    Form of Compliance Certificate

D    Form of Closing Certificate

E    Form of Assignment and Assumption

F    [Reserved]

G    Forms of U.S. Tax Compliance Certificates

H    Form of Note

I    Form of Solvency Certificate

This TERM LOAN CREDIT AGREEMENT (this “Agreement”), dated as of July 1, 2020, among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), the several banks and other financial institutions or entities from time to time parties to this Agreement (the “Lenders”) and JPMORGAN CHASE BANK, N.A., as administrative agent (in such capacity, together with any permitted successor thereto, the “Administrative Agent”).

W I T N E S S E T H:

WHEREAS, on January 29, 2019, the Borrower and PG&E Corporation, a California corporation and the holder of all of the issued and outstanding common stock of the Borrower (“PCG”) filed voluntary petitions for relief in the United States Bankruptcy Court for the Northern District of California (the “Bankruptcy Court”), and commenced their respective cases under chapter 11 of title 11 of the United States Code;

WHEREAS, on June 19, 2020, the Borrower and PCG filed the Debtors’ and Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization Dated June 19, 2020 [Docket No. 8048] (together with all exhibits, schedules, annexes, supplements, and other attachments thereto, and as may be further amended, modified or otherwise changed in accordance with this Agreement, the “Plan of Reorganization”);

WHEREAS, on June 20, 2020, the Plan of Reorganization was confirmed by the Bankruptcy Court and was consummated on the Effective Date;

WHEREAS, in connection with the foregoing, the Borrower has requested that the Lenders provide the term loans set forth herein and the Lenders are willing to make available to the Borrower such term loans upon the terms and subject to the conditions set forth herein; and

WHEREAS, in connection with and pursuant to Amendment No. 1, the Borrower has requested that this Agreement be amended as set forth in Amendment No. 1.

NOW, THEREFORE, IT IS AGREED AS FOLLOWS:

Section 1.DEFINITIONS

1.1Defined Terms. As used in this Agreement, the terms listed in this Section 1.1 shall have the respective meanings set forth in this Section 1.1.

“18-Month Tranche Commitment”: as to each 18-Month Tranche Lender, its obligation to make Loans under the 18-Month Tranche to the Borrower on the Effective Date pursuant to Section 2.1(b), in an aggregate principal amount equal to the amount set forth opposite such 18-Month Tranche Lender’s name on Schedule 1.1, as such amount may be adjusted from time to time in accordance with this Agreement. As of the Effective Date, the aggregate amount of the 18-Month Tranche Commitments for all 18-Month Tranche Lenders is $1,500,000,000.

“18-Month Tranche Lender”: a Lender with an 18-Month Tranche Commitment or holding 18-Month Tranche Loans.

“18-Month Tranche Loans”: as defined in Section 2.1(b).

“18-Month Tranche Loans(Tranche A)”: as defined in Section 2.1(b).

“18-Month Tranche Loans(Tranche B)”: as defined in Section 2.1(b).

“18-Month Tranche Maturity Date”: (a) with respect to the 18-Month Tranche Loans (Tranche A), October 1, 2022 and (b) with respect to the 18-Month Tranche Loans (Tranche B), January 1, 2022.

“364-Day Tranche Commitment”: as to each 364-Day Tranche Lender, its obligation to make Loans under the 364-Day Tranche to the Borrower on the Effective Date pursuant to Section 2.1(a), in an aggregate principal amount equal to the amount set forth opposite such 364-Day Tranche Lender’s name on Schedule 1.1, as such amount may be adjusted from time to time in accordance with this Agreement. As of the Effective Date, the aggregate amount of the 364-Day Tranche Commitments for all 364-Day Tranche Lenders is $1,500,000,000.

“364-Day Tranche Lender”: a Lender with a 364-Day Tranche Commitment or holding 364-Day Tranche Loans.

“364-Day Tranche Loans”: as defined in Section 2.1(a).

“364-Day Tranche Maturity Date”: the date that is 364 days after the Effective Date.

“ABR”: for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the NYFRB Rate in effect on such day plus ½ of 1% and (c) the Eurodollar Rate for a one month Interest Period commencing on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1%; provided that for the purpose of this definition, the Eurodollar Rate for any day shall be based on the Eurodollar Screen Rate (or if the Eurodollar Screen Rate is not available for such one month Interest Period, the Interpolated Rate) at approximately 11:00 a.m. London time on such day. Any change in the ABR due to a change in the Prime Rate, the NYFRB Rate or the Eurodollar Rate shall be effective from and including the effective date of such change in the Prime Rate, the NYFRB Rate or the Eurodollar Rate, respectively. If ABR is being used as an alternate rate of interest pursuant to Section 2.13 (for the avoidance of doubt, only until any amendment has become effective pursuant to Section 2.13(b)), then ABR shall be the greater of clauses (a) and (b) above and shall be determined without reference to clause (c) above. If the ABR as determined pursuant to the foregoing would be less than 1.00%, such rate shall be deemed to be 1.00% for purposes of this Agreement.

“ABR Loans”: Loans the rate of interest applicable to which is based upon the ABR.

“Administrative Agent”: as defined in the preamble hereto.

“Affected Financial Institution”: (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Affiliate”: with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“Agent Parties”: as defined in Section 10.2(d)(ii).

“Agents”: the collective reference to the Syndication Agents, the Documentation Agents, and the Administrative Agent.

“Agreement”: as defined in the preamble hereto.

“Amendment No. 1”: that certain Amendment No. 1 to Credit Agreement, dated as of the Amendment No. 1 Effective Date, among the Borrower, each Lender party thereto, and JPMorgan Chase Bank, N.A., as administrative agent.

“Amendment No. 1 Effective Date”: October 29, 2021.

“Amendment No. 2”: that certain Amendment No. 2 to Credit Agreement, dated as of the Amendment No. 2 Effective Date, among the Borrower, each Lender party thereto, and JPMorgan Chase Bank, N.A., as administrative agent.

“Amendment No. 2 Effective Date”: December [●], 2021.

“Anti-Corruption Laws”: as defined in Section 4.15.

“Applicable Margin”: for any day, (a) (i) with respect to any ABR Loans under the 364-Day Tranche, 1.00% per annum and (ii) with respect to Eurodollar Loans under the 364-Day Tranche, 2.00% per annum and (b) (i) with respect to any ABR Loans under the 18-Month Tranche, 1.25% per annum and (ii) with respect to Eurodollar Loans under the 18-Month Tranche, 2.25% per annum.

“Approved Fund”: with respect to any Lender, any Person (other than a natural person) that is engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business that is administered or managed by (a) such Lender, (b) an Affiliate of such Lender or (c) an entity or an Affiliate of any entity that administers or manages such Lender.

“Arrangers”: the Joint Lead Arrangers and Joint Bookrunners identified on the cover hereto.

“A/R Securitization Assets”: (i) any accounts receivable, notes receivable, rights to future accounts receivable, notes receivable or residuals or other similar rights to payments due or any other rights to payment or related assets in respect of the provision of gas and electric service to consumers or otherwise (whether then existing or arising in the future) of the Borrower or any of its Subsidiaries and the proceeds thereof and (ii) all collateral securing such receivable or asset, all contracts and contract rights, guarantees or other obligations in respect of such receivable or asset, lockbox accounts and records with respect to such receivables or asset and any other assets customarily transferred (or in respect of which security interests are customarily granted) together with receivables or assets in connection with a securitization transaction involving such assets.

“A/R Securitization Subsidiary”: PG&E AR Facility, LLC and any other Subsidiary formed and operating solely for the purpose of entering into A/R Securitization Transactions and engaging in activities ancillary thereto.

“A/R Securitization Transaction”: any financing transaction or series of financing transactions entered into by the Borrower or any Subsidiary of the Borrower pursuant to which the Borrower may sell, convey or otherwise transfer to any Person (including, without limitation, an A/R Securitization Subsidiary), or may grant a security interest in any A/R Securitization Assets and that are (other than to the extent of the Standard A/R Securitization Obligations) non-recourse to the Borrower or any of its Subsidiaries (other than an A/R Securitization Subsidiary).

“Assignee”: as defined in Section 10.6(b).

“Assignment and Assumption”: an Assignment and Assumption, substantially in the form of Exhibit E.

“Available Tenor”: as of any date of determination and with respect to the then-current Benchmark, as applicable, (x) if the then-current Benchmark is a term rate, any tenor for such Benchmark that is or may be used for determining the length of an Interest Period or (y) otherwise, any payment period for interest calculated with reference to such Benchmark, as applicable, pursuant to this Agreement as of such date.

“Bail-In Action”: the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation”: (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation, rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Bankruptcy Court”: as defined in the first recital paragraph.

“Benchmark”: initially, the Eurodollar Base Rate; provided that if a replacement of the Benchmark has occurred pursuant to Section 2.13, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate. Any reference to “Benchmark” shall include, as applicable, the published component used in the calculation thereof.

“Benchmark Replacement”: for any Available Tenor:

(1) for purposes of Section 2.13(b), the first alternative set forth below that can be determined by the Administrative Agent:

(a) the sum of: (i) Term SOFR and (ii) 0.11448% (11.448 basis points) for an Available Tenor of one-month’s duration, 0.26161% (26.161 basis points) for an Available Tenor of three-months’ duration, 0.42826% (42.826 basis points) for an Available Tenor of six-months’ duration and 0.71513% (71.513 basis points) for an Available Tenor of twelve-months’ duration; provided, that if any Available Tenor of the Eurodollar Base Rate does not correspond to an Available Tenor of Term SOFR, the Benchmark Replacement for such Available Tenor of the Eurodollar Base Rate shall be the closest corresponding Available Tenor (based on tenor) for Term SOFR, or and if such Available Tenor of the Eurodollar Base Rate corresponds equally to two Available Tenors of Term SOFR, the corresponding tenor of Term SOFR with the shorter duration shall be applied;

(b) the sum of: (i) Daily Simple SOFR and (ii) the spread adjustment selected or recommended by the Relevant Governmental Body for the replacement of the tenor of the Eurodollar Base Rate with a SOFR-based rate having approximately the same length as the interest payment period specified in clause (b) of Section

2.13 (which spread adjustment, for the avoidance of doubt, shall be 0.11448% (11.448 basis points); and

(2) for purposes of clause (c) of Section 2.13, the sum of (a) the alternate benchmark rate and (b) an adjustment (which may be a positive or negative value or zero), in each case, that has been selected by the Administrative Agent and the Borrower as the replacement for such Available Tenor of such Benchmark giving due consideration to any evolving or then-prevailing market convention, including any applicable recommendations made by the Relevant Governmental Body, for U.S. dollar-denominated syndicated credit facilities at such time;

provided that, if the Benchmark Replacement as determined pursuant to clause (1) or (2) above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Loan Documents.

“Benchmark Replacement Conforming Changes”: with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “ABR,” the definition of “Business Day,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, the applicability and length of lookback periods, the applicability of breakage provisions, the formula for calculating any successor rates identified pursuant to the definition of “Benchmark Replacement” and other technical, administrative or operational matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of such Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Loan Documents), the formula, methodology or convention for applying the successor Floor to the successor Benchmark Replacement.

“Benchmark Transition Event”: with respect to any then-current Benchmark other than the Eurodollar Base Rate, the occurrence of one or more of the following events: a public statement or publication of information by or on behalf of the administrator of the then-current Benchmark, the regulatory supervisor for the administrator of such Benchmark, the Federal Reserve Board, the NYFRB, an insolvency official with jurisdiction over the administrator for such Benchmark, a resolution authority with jurisdiction over the administrator for such Benchmark or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark, announcing or stating that (a) such administrator has ceased or will cease on a specified date to provide all Available Tenors of such Benchmark, permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark or (b) all Available Tenors of such Benchmark are or will no longer be representative of the underlying market and economic reality that such Benchmark is intended to measure and that representativeness will not be restored.

“Beneficial Owner”: as defined in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Sections 13(d) and 14(d) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire

by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Beneficial Ownership Certification”: a certification regarding beneficial ownership or control as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation”: 31 C.F.R. § 1010.230.

“Benefit Plan”: any of (a) an “employee benefit plan” (as defined in ERISA) that is subject to Title I of ERISA, (b) a “plan” as defined in and subject to Section 4975 of the Code or (c) any Person whose assets include (for purposes of ERISA Section 3(42) or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.

“Benefitted Lender”: as defined in Section 10.7(a).

“BHC Act Affiliate”: an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)).

“Bond Delivery Agreement”: (i) that certain Bond Delivery Agreement, dated as of the Effective Date, between the Borrower and the Administrative Agent and (ii) that certain Bond Delivery Agreement, dated as of the Amendment No. 1 Effective Date, between the Borrower and the Administrative Agent.

“Bond Documents”: collectively, the FMB Indenture, the Supplemental Indenture, the Senior Bonds and the Bond Delivery Agreement.

“Borrower”: as defined in the preamble hereto.

“Bridge Facilities”: each of the bridge facilities outstanding, as of any date of determination, pursuant to the terms of the Utility Commitment Letter and the PCG Commitment Letter.

“Business Day”: a day other than a Saturday, Sunday or other day on which commercial banks in New York City or San Francisco, California are authorized or required by law to close, provided, that with respect to notices and determinations in connection with, and payments of principal and interest on, Eurodollar Loans, such day is also a day for trading by and between banks in Dollar deposits in the London interbank eurodollar market.

“Capital Lease Obligations”: as to any Person, the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on the balance sheet of such Person under GAAP and, for the purposes of this Agreement, the amount of such obligations at any time shall be the capitalized amount thereof at such time determined in accordance with GAAP, subject to Section 1.2(f).

“Capital Stock”: any and all shares, interests, participations or other equivalents (however designated) of capital stock of a corporation, any and all equivalent ownership interests in a Person (other than a corporation) and any and all warrants, rights or options to purchase any of the foregoing.

“Cash Management Agreement”: any agreement to establish or maintain accounts or provide cash management services, including treasury, depository, overdraft, netting services, cash pooling arrangements, credit or debit card, purchasing card, electronic funds transfer, automated clearing house, foreign exchange facilities and other cash management arrangements.

“Change of Control”: the occurrence of one of the following:

Section 2.(A) PCG shall at any time not be the Beneficial Owner of 100% of the common stock of the Borrower or (B) PCG shall at any time not be the Beneficial Owner of at least 70% of the voting Capital Stock of the Borrower; or

Section 3.any person or group (within the meaning of the Exchange Act and the rules of the SEC thereunder as of the Effective Date) shall become the Beneficial Owner of shares representing more than 35% of the voting power of the Capital Stock of PCG; or

Section 4.at any point during any period of 24 consecutive months, commencing after the Effective Date, individuals who at the beginning of such 24-month period were directors of PCG, together with any directors whose election or nomination for election to the board of directors of PCG (whether by the board of directors of PCG or any shareholder of PCG) was approved by a majority of the directors who either were directors of PCG at the beginning of such 24-month period or whose election or nomination for election was so approved, cease to constitute a majority of the board of directors of PCG (it being understood and agreed that, for the avoidance of doubt, the change of directors of PCG contemplated by the Plan of Reorganization shall not constitute a Change of Control); or

Section 5.there shall have been (A) [reserved] or (B) a transfer of the license and/or operating assets constituting more than 10% of the Net Tangible Assets of the Borrower to the State of California, to any other Governmental Authority or to a third party at the direction of State of California, the CPUC or any similar Governmental Authority.

“Change of Law”: the occurrence, after the Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation, statute, treaty, policy, guideline or directive by any Governmental Authority, (b) any change in any law, rule, regulation, statute, treaty, policy, guideline or directive or in the application, interpretation, promulgation, implementation, administration or enforcement thereof by any Governmental Authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change of Law”, regardless of the date enacted, adopted or issued.

“Code”: the Internal Revenue Code of 1986, as amended from time to time.

“Commitment”: as to any Lender, its 364-Day Tranche Commitment or 18-Month Tranche Commitment.

“Commitment Letter”: that certain Term Loan Commitment Letter dated as of May 26, 2020 among Pacific Gas and Electric Company, as the borrower, PG&E Corporation and the commitment parties from time to time party thereto, as amended, modified or supplemented from time to time prior to the date hereof.

“Commonly Controlled Entity”: an entity, whether or not incorporated, that is under common control with the Borrower within the meaning of Section 4001 of ERISA or is part of a group that includes the Borrower and that is treated as a single employer under Section 414 of the Code.

“Communications”: as defined in Section 10.2(d)(ii).

“Compliance Certificate”: a certificate duly executed by a Responsible Officer substantially in the form of Exhibit C.

“Conduit Lender”: any special purpose corporation organized and administered by any Lender for the purpose of making Loans otherwise required to be made by such Lender and designated by such Lender in a written instrument; provided, that the designation by any Lender of a Conduit Lender shall not relieve the designating Lender of any of its obligations to fund a Loan under this Agreement if, for any reason, its Conduit Lender fails to fund any such Loan, and the designating Lender (and not the Conduit Lender) shall have the sole right and responsibility to deliver all consents and waivers required or requested under this Agreement with respect to its Conduit Lender, and provided, further, that no Conduit Lender shall (a) be entitled to receive any greater amount pursuant to Sections 2.15, 2.16, 2.17 or 10.5 than the designating Lender would have been entitled to receive in respect of the extensions of credit made by such Conduit Lender or (b) be deemed to have any Commitment.

“Connection Income Taxes”: Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Consolidated Capitalization”: on any date of determination, the sum of (a) Consolidated Total Debt on such date, plus without duplication, (b) (i) the amounts set forth opposite the captions “common shareholders’ equity” (or any similar caption) and “preferred stock” (or any similar caption) on the consolidated balance sheet, prepared in accordance with GAAP, of the Borrower and its Subsidiaries as of such date, and (ii) the outstanding principal amount of any junior subordinated deferrable interest debentures or other similar securities issued by the Borrower or any of its Subsidiaries after the Effective Date.

“Consolidated Capitalization Ratio”: on any date of determination, the ratio of (a) Consolidated Total Debt to (b) Consolidated Capitalization.

“Consolidated Total Debt”: at any date, the aggregate principal amount of all obligations of the Borrower and its Significant Subsidiaries at such date that in accordance with GAAP would be classified as debt on a consolidated balance sheet of the Borrower, and without duplication all Guarantee Obligations of the Borrower and its Significant Subsidiaries at such date in respect of obligations of any other Person that in accordance with GAAP would be classified as debt on a consolidated balance sheet of such Person; provided that, the determination of “Consolidated Total Debt” shall exclude, without duplication, (a) the Securitized Bonds and any Indebtedness under any A/R Securitization Transaction, (b) Indebtedness of the Borrower and its Significant Subsidiaries in an amount equal to the amount of cash held as cash collateral for any fully

cash collateralized letter of credit issued for the account of the Borrower or any Significant Subsidiary, (c) imputed Indebtedness of the Borrower or any Significant Subsidiary incurred in connection with power purchase and fuel agreements, (d) any junior subordinated deferrable interest debenture or other similar securities issued by the Borrower and (e) as of any date of determination, the amount of any securities included within the caption “preferred stock” (or any similar caption) on a consolidated balance sheet, prepared in accordance with GAAP, of the Borrower as of such date.

“Contractual Obligation”: as to any Person, any provision of any security issued by such Person or of any agreement, instrument or other undertaking to which such Person is a party or by which it or any of its property is bound.

“Control”: the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. “Controlling” and “Controlled” have meanings correlative thereto.

“Covered Entity”: any of the following:

(i)a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b);

Section 6.a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or

Section 7.a “covered FSI” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).

“Covered Party”: as defined in Section 10.19.

“CPUC”: the California Public Utilities Commission or its successor.

“Daily Simple SOFR”: for any day, SOFR, with the conventions for this rate (which will include a lookback) being established by the Administrative Agent in accordance with the conventions for this rate recommended by the Relevant Governmental Body for determining “Daily Simple SOFR” for syndicated business loans; provided, that if the Administrative Agent decides that any such convention is not administratively feasible for the Administrative Agent, then the Administrative Agent may establish another convention in its reasonable discretion.

“Debt Issuance”: the issuance of Securitized Bonds under or pursuant to the Application of Pacific Gas and Electric Company for (1) Administration of Stress Test Methodology Developed Pursuant to Public Utilities Code Section 451.2(b) and (2) Determination That $7.5 Billion of 2017 Catastrophic Wildfire Costs and Expenses Are Stress Test Costs That May Be Financed Through Issuance of Recovery Bonds Pursuant to Section 451.2(c) and Section 850 et seq. (U39E) - Application No. 20-04-023 dated as of April 30, 2020, or the contemplated subsequent and related application for the issuance of a financing order authorizing the securitization transaction described in A.20-04-023, to be filed later in 2020 and consolidated therewith, by the Borrower or any of its Subsidiaries.

“Debtor Relief Laws”: the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor

relief laws of the United States or other applicable jurisdictions from time to time in effect.

“Default”: any of the events specified in Section 8, whether or not any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

“Default Right”: the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

“Defaulting Lender”: subject to the penultimate paragraph of Section 2.20, any Lender, as reasonably determined by the Administrative Agent, that has (a) failed to fund any portion of its Loans within two (2) Business Days of the date required to be funded by it under this Agreement, unless such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable Default, shall be specifically identified in such writing) has not been satisfied, (b) notified the Borrower, the Administrative Agent or any other Lender in writing that it does not intend to comply with any of its funding obligations under this Agreement or has made a public statement to the effect that it does not intend to comply with its funding obligations under this Agreement (other than a notice of a good faith dispute or related communications) or generally under other agreements in which it commits to extend credit, unless such writing or public statement relates to such Lender’s obligation to fund a Loan hereunder and states that such position is based on such Lender’s good faith determination that a condition precedent to funding (which condition precedent, together with any applicable Default, shall be specifically identified in such writing or public statement) cannot be satisfied, (c) failed, within two (2) Business Days after written request by the Administrative Agent or the Borrower, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund prospective Loans, unless the subject of a good faith dispute (provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent or the Borrower), (d) otherwise failed to pay over to the Administrative Agent or any other Lender any other amount required to be paid by it under this Agreement within two (2) Business Days of the date when due, unless the subject of a good faith dispute, or (e) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had a custodian appointed for it, or has consented to, approved of or acquiesced in any such proceeding or appointment or has a parent company that has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it, or has consented to, approved of or acquiesced in any such proceeding or appointment, or (iii) become the subject of a Bail-In Action; provided that (x) if a Lender would be a “Defaulting Lender” solely by reason of events relating to a parent company of such Lender or solely because a Governmental Authority has been appointed as receiver, conservator, trustee or custodian for such Lender, in each case as described in clause (e) above, the Administrative Agent may, in its discretion, determine that such Lender is not a “Defaulting Lender” if and for so long as the Administrative Agent is satisfied that such Lender will continue to perform its funding obligations hereunder and (y) a Lender shall not be a Defaulting Lender solely by virtue of the ownership or acquisition of voting stock or any other Capital Stock in such Lender or a parent company thereof by a Governmental Authority or an instrumentality thereof, or the exercise of control over such Lender or parent company thereof, by a Governmental Authority or instrumentality thereof so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm

any contracts or agreements made with such Lender. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (a) through (e) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to the penultimate paragraph of Section 2.20) upon delivery of written notice of such determination to the Borrower and each Lender.

“Disposition”: with respect to any property, any sale, lease, sale and leaseback, assignment, conveyance, transfer or other disposition thereof. The term “Dispose of” shall have a correlative meaning.

“Documentation Agents”: as defined on the cover hereto.

“Dollars” and “$”: dollars in lawful currency of the United States.

“Early Opt-in Effective Date”: with respect to any Early Opt-in Election, the sixth (6th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, so long as the Administrative Agent has not received, by 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, written notice of objection to such Early Opt-in Election from Lenders comprising the Required Lenders.

“Early Opt-in Election”: the occurrence of the following:

(1)    a notification by the Administrative Agent to (or the request by the Borrower to the Administrative Agent to notify) each of the other parties hereto that at least five currently outstanding U.S. dollar-denominated syndicated credit facilities in the U.S. syndicated loan market at such time contain (as a result of amendment or as originally executed) a SOFR-based rate (including SOFR, a term SOFR or any other rate based upon SOFR) as a benchmark rate (and such syndicated credit facilities are identified in such notice and are publicly available for review); and

(2)    the joint election by the Administrative Agent and the Borrower to trigger a fallback from Eurodollar Base Rate and the provision by the Administrative Agent of written notice of such election to the Lenders.

“EEA Financial Institution”: (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country”: any of the member states of the European Union, Iceland, Liechtenstein and Norway.

“EEA Resolution Authority”: any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Effective Date”: the date on which the conditions precedent set forth in Section 5.1 shall have been satisfied or waived, which date is July 1, 2020.

“Eligible Assignee”: (a) any commercial bank or other financial institution having a senior unsecured debt rating by Moody’s of A3 or better and by S&P of A- or better, which is domiciled in a country which is a member of the OECD or (b) with respect to any Person referred to in the preceding clause (a), any other Person that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of business all of the Capital Stock of which is owned, directly or indirectly, by such Person; provided that in the case of clause (b), the Administrative Agent shall have consented to the designation of such Person as an Eligible Assignee (such consent not to be unreasonably withheld or delayed).

“Environmental Laws”: any and all foreign, Federal, state, local or municipal laws, rules, orders, regulations, statutes, ordinances, codes, decrees, requirements of any Governmental Authority or other Requirements of Law (including common law) regulating, relating to or imposing liability or standards of conduct concerning protection of human health or the environment, as now or may at any time hereafter be in effect.

“ERISA”: the Employee Retirement Income Security Act of 1974, as amended from time to time.

“ERISA Event”: (a) any Reportable Event; (b) the failure of the Borrower or any Commonly Controlled Entity to timely make a required contribution with respect to any Plan or any Multiemployer Plan; (c) the imposition of a Lien under Section 430 of the Code or Section 303 of ERISA with respect to any Single Employer Plan; (d) the failure of the Borrower or any Commonly Controlled Entity to meet the minimum funding standard under Section 412 or 430 of the Code with respect to any Plan or the filing of an application for a funding waiver with respect to any Single Employer Plan; (e) the incurrence by the Borrower or any Commonly Controlled Entity of any liability under Title IV of ERISA, including with respect to the termination of any Plan (other than the payment of PBGC premiums in the ordinary course); (f) (i) the termination of, or the filing or receipt of a notice of intent to terminate, a Single Employer Plan under Section 4041 of ERISA, or the treatment of a plan amendment as a termination under Section 4041 of ERISA, or (ii) (A) the appointment of a trustee to administer a Single Employer Plan under Section 4042, or (B) the institution by the PBGC of proceedings to terminate a Single Employer Plan or to have a trustee appointed to administer a Single Employer Plan, or receipt by the Borrower of notice from the PBGC thereof, where such proceedings continue unstayed or in effect for more than 60 days, or such notice is not withdrawn by the PBGC within 60 days following delivery by PBGC; (g) the incurrence by the Borrower or any Commonly Controlled Entity of any liability with respect to the complete withdrawal or partial withdrawal under Title IV of ERISA from any Multiemployer Plan; (h) the receipt by the Borrower or any Commonly Controlled Entity of any notice from a Multiemployer Plan concerning the imposition of Withdrawal Liability; (i) receipt of notification by Borrower or any Commonly Controlled Entity from a Multiemployer Plan that such Multiemployer Plan is in endangered or critical status (within the meaning of Section 305 of ERISA) or in Insolvency; (j) the incurrence by the Borrower or any Commonly Controlled Entity of any liability pursuant to Section 4063 or 4064 of ERISA or a substantial cessation of operations with respect to a Plan within the meaning of Section 4062(e) of ERISA; (k) the posting of a bond or security under Section 436(f) of the Code with respect to any Plan; or (l) the Borrower incurs material tax liability with respect to any Plan (including Sections 4975, 4980B, 4980D, 4980H and 4980I of the Code, as applicable).

“Erroneous Payment”: as defined in Section 9.13(a).

“EU Bail-In Legislation Schedule”: the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Eurocurrency Liabilities”: as defined in Regulation D of the Federal Reserve Board.

“Eurocurrency Reserve Requirements”: of any Lender for any Interest Period as applied to a Eurodollar Loan, the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during any such percentage shall be so applicable) under any regulations of the Federal Reserve Board or other Governmental Authority having jurisdiction with respect to determining the maximum reserve requirement (including basic, supplemental and emergency reserves) for such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period.

“Eurodollar Base Rate”: with respect to each day during each Interest Period pertaining to a Eurodollar Loan, the Eurodollar Screen Rate at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period; provided that if the Eurodollar Screen Rate shall not be available at such time for such Interest Period (an “Impacted Interest Period”) then the Eurodollar Base Rate shall be the Interpolated Rate.

“Eurodollar Loans”: Loans the rate of interest applicable to which is based upon the Eurodollar Rate.

“Eurodollar Rate”: with respect to each day during each Interest Period pertaining to a Eurodollar Loan, a rate per annum determined for such day in accordance with the following formula (rounded upwards, if necessary, to the next 1/16 of 1%):

Eurodollar Base Rate

1.00 - Eurocurrency Reserve Requirements

“Eurodollar Screen Rate”: for any day and time, with respect to any Eurodollar Loan for any Interest Period, the London interbank offered rate as administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate) for a period equal in length to such Interest Period as displayed on such day and time on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate (or, in the event such rate does not appear on a Reuters page or screen, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion); provided that if the Eurodollar Screen Rate as so determined would be less than zero, such rate shall be deemed to zero for the purposes of this Agreement.

“Eurodollar Tranche”: the collective reference to Eurodollar Loans the then current Interest Periods with respect to all of which begin on the same date and end on the same later date (whether or not such Loans shall originally have been made on the same day).

“Event of Default”: any of the events specified in Section 8, provided that any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

“Exchange Act”: Securities Exchange Act of 1934, as amended.

“Excluded Taxes”: any of the following Taxes imposed on or with respect to any Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan (other than pursuant to an assignment request by the Borrower under Section 2.19) or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 2.16(a) or (c), amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.16(e) and (d) any U.S. federal withholding Taxes imposed pursuant to FATCA.

“FATCA”: Sections 1471 through 1474 of the Code, as of the Effective Date (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreements entered into pursuant to Section 1471(b)(1) of the Code.

“FCA”: as defined in Section 2.13(b).

“FCPA”: as defined in Section 4.15.

“Federal Funds Effective Rate”: for any day, the rate calculated by the NYFRB based on such day’s federal funds transactions by depositary institutions, as determined in such manner as shall be set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as the effective federal funds rate; provided that if the Federal Funds Effective Rate as so determined would be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

“Federal Reserve Board”: the Board of Governors of the Federal Reserve System of the United States of America.

“First Mortgage Bonds”: bonds issued by the Borrower pursuant to the FMB Indenture.

“Floor”: the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to Eurodollar Base Rate.

“FMB Indenture”: the Indenture of Mortgage (Mortgage), dated as of June 19, 2020, between the Borrower and the Indenture Trustee (as supplemented by the Supplemental Indenture) and as further supplemented or amended from time to time.

“Foreign Lender”: a Lender that is not a U.S. Person.

“FPA”: the Federal Power Act, as amended, and the rules and regulations promulgated thereunder.

“Funding Office”: the office of the Administrative Agent specified in Section 10.2(a) or such other office as may be specified from time to time by the Administrative Agent as its funding office by written notice to the Borrower and the Lenders.

“GAAP”: generally accepted accounting principles in the United States as in effect from time to time, except as noted below. In the event that any “Change in Accounting Principles” (as defined below) shall occur and such change results in a change in the method of calculation of financial covenants, standards or terms in this Agreement, then, upon the request of the Borrower or the Required Lenders, the Borrower and the Administrative Agent agree to enter into negotiations in order to amend such provisions of this Agreement so as to reflect equitably such Change in Accounting Principles with the desired result that the criteria for evaluating the Borrower’s financial condition shall be the same after such Change in Accounting Principles as if such Change in Accounting Principles had not been made. Until such time as such an amendment shall have been executed and delivered by the Borrower, the Administrative Agent and the Required Lenders, all financial covenants, standards and terms in this Agreement shall continue to be calculated or construed as if such Change in Accounting Principles had not occurred. “Change in Accounting Principles” refers to (i) changes in accounting principles required by the promulgation of any rule, regulation, pronouncement or opinion by the Financial Accounting Standards Board of the American Institute of Certified Public Accountants or any successor thereto, the SEC or, if applicable, the Public Company Accounting Oversight Board and (ii) any change in the application of GAAP concurred by the Borrower’s independent public accountants and disclosed in writing to the Administrative Agent.

“Governmental Authority”: any nation or government, any state or other political subdivision thereof, any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative functions of or pertaining to government, any securities exchange and any self-regulatory organization (including the National Association of Insurance Commissioners and supra-national bodies such as the European Union or the European Central Bank).

“Guarantee Obligation”: as to any Person (the “guaranteeing person”), any obligation, including a reimbursement, counterindemnity or similar obligation, of the guaranteeing person that guarantees any Indebtedness, leases, dividends or other obligations (the “primary obligations”) of any other third Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of the guaranteeing person, whether or not contingent, (i) to purchase any such primary obligation or any property constituting direct or indirect security therefor, (ii) to advance or supply funds (1) for the purchase or payment of any such primary obligation or (2) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (iii) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation, (iv) otherwise to assure or hold harmless the owner of any such primary obligation against loss in respect thereof or (v) to reimburse or indemnify an issuer of a letter of credit, surety bond or guarantee issued by such issuer in respect of primary obligations of a primary obligor other than the Borrower or any Significant Subsidiary; provided, however, that the term Guarantee Obligation shall not include endorsements of instruments for deposit or collection in the ordinary course of business. The amount of any Guarantee Obligation of any guaranteeing person shall be deemed to be the lower of (a) an amount equal to the stated or determinable amount of the primary obligation in respect of which such Guarantee Obligation is made and (b) the maximum amount for which such guaranteeing

person may be liable pursuant to the terms of the instrument embodying such Guarantee Obligation, unless such primary obligation and the maximum amount for which such guaranteeing person may be liable are not stated or determinable, in which case the amount of such Guarantee Obligation shall be such guaranteeing person’s reasonably anticipated liability in respect thereof as determined by the Borrower in good faith.

“IBA”: as defined in Section 2.13(b).

“Indebtedness”: of any Person at any date, without duplication, (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person for the deferred purchase price of property or services (other than trade payables, including under energy procurement and transportation contracts, incurred in the ordinary course of such Person’s business), (c) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (d) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), (e) all Capital Lease Obligations of such Person, (f) all obligations of such Person, contingent or otherwise, as an account party or applicant under or in respect of acceptances, letters of credit, surety bonds or similar arrangements (other than reimbursement obligations, which are not due and payable on such date, in respect of documentary letters of credit issued to provide for the payment of goods and services in the ordinary course of business), (g) the liquidation value of all mandatorily redeemable preferred Capital Stock of such Person, (h) all Guarantee Obligations of such Person in respect of obligations of the kind referred to in clauses (a) through (g) above, (i) all obligations of the kind referred to in clauses (a) through (h) above secured by (or for which the holder of such obligation has an existing right, contingent or otherwise, to be secured by) any Lien on property (including accounts and contract rights) owned by such Person, whether or not such Person has assumed or become liable for the payment of such obligation (provided, that if such Person is not liable for such obligation, the amount of such Person’s Indebtedness with respect thereto shall be deemed to be the lesser of the stated amount of such obligation and the value of the property subject to such Lien), and (j) for the purposes of Sections 7.1 and 8(e) only, all obligations of such Person in respect of Swap Agreements, provided that Indebtedness as used in this Agreement shall exclude any Non-Recourse Debt and any obligations under any A/R Securitization Transaction. The Indebtedness of any Person shall include the Indebtedness of any other entity (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person’s ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness expressly provide that such Person is not liable therefor.

“Indebtedness Covenant Release Date”: the date of the expiration of the temporary waiver from its authorized capital structure granted by the CPUC on May 28, 2020.

“Indemnified Liabilities”: as defined in Section 10.5.

“Indemnified Taxes”: (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.

“Indemnitee”: as defined in Section 10.5.

“Indenture Trustee”: The Bank of New York Mellon Trust Company, N.A. and any successor thereto as trustee under the FMB Indenture.

“Insolvency”: with respect to any Multiemployer Plan, the condition that such plan is insolvent within the meaning of Section 4245 of ERISA.

“Interest Payment Date”: (a) as to any ABR Loan, the last day of each March, June, September and December to occur while such Loan is outstanding and the final maturity date of such Loan, (b) as to any Eurodollar Loan having an Interest Period of three months or less, the last day of such Interest Period, (c) as to any Eurodollar Loan having an Interest Period longer than three months, each day that is three months, or a whole multiple thereof, after the first day of such Interest Period and the last day of such Interest Period and (d) as to any Loan, the date of any repayment or prepayment made in respect thereof.

“Interest Period”: as to any Eurodollar Loan, (a) initially, the period commencing on the borrowing or conversion date, as the case may be, with respect to such Eurodollar Loan and ending one week thereafter or one, three or six or (if agreed to by all Lenders) twelve months thereafter, as selected by the Borrower in its notice of borrowing or notice of conversion, as the case may be, given with respect thereto; and (b) thereafter, each period commencing on the last day of the next preceding Interest Period applicable to such Eurodollar Loan and ending one, three or six or (if agreed to by all Lenders) twelve months thereafter, as selected by the Borrower by irrevocable notice to the Administrative Agent not later than 12:00 Noon, New York City time, on the date that is three Business Days prior to the last day of the then current Interest Period with respect thereto; provided that, all of the foregoing provisions relating to Interest Periods are subject to the following:

(i)if any Interest Period would otherwise end on a day that is not a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless the result of such extension would be to carry such Interest Period into another calendar month in which event such Interest Period shall end on the immediately preceding Business Day;

Section 8.the Borrower may not select an Interest Period that would extend beyond the applicable Maturity Date;

Section 9.any Interest Period that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of a calendar month;

Section 10.[reserved];

Section 11.at the election of the Borrower, the initial Interest Period for any Eurodollar Loans made on the Effective Date, shall commence on the Effective Date and end on the last day of the calendar month during which the Effective Date occurs; and

Section 12.the option to elect a one week Interest Period shall only be available during the calendar year ending December 31, 2021 and solely to the extent such Interest Period is available to the Administrative Agent.

“Interpolated Rate”: at any time, for any Interest Period, the rate per annum (rounded to the same number of decimal places as the Eurodollar Screen Rate) determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the Eurodollar Screen Rate for the longest period (for which the Eurodollar

Screen Rate is available) that is shorter than the Impacted Interest Period; and (b) the Eurodollar Screen Rate for the shortest period (for which that Eurodollar Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“IRS”: the United States Internal Revenue Service.

“knowledge of the Borrower”: actual knowledge of any Responsible Officer of the Borrower.

“Laws”: collectively, all international, foreign, federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, requests, licenses, authorizations and permits of, and agreements with, any Governmental Authority, in each case whether or not having the force of law.

“Lenders”: as defined in the preamble hereto, including each Lender set forth under the heading “Lender” on Schedule I of Amendment No. 1 and their respective successors and assigns as permitted hereunder; provided, that unless the context otherwise requires, each reference herein to the Lenders shall be deemed to include any Conduit Lender.

“LIBOR”: as defined in Section 1.4.

“Lien”: any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge or other security interest or any preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever (including any conditional sale or other title retention agreement and any Capital Lease Obligation having substantially the same economic effect as any of the foregoing).

“Loans”: the 364-Day Tranche Loans and the 18-Month Tranche Loans.

“Loan Documents”: this Agreement, the Notes, the Supplemental Indenture, the Senior Bonds, the Bond Delivery Agreement, the FMB Indenture and, in each case, any amendment, waiver, supplement or other modification to any of the foregoing; provided, that the term “Loan Documents” shall not include the FMB Indenture for any purposes under Section 2.16, Section 8 or Section 10 (other than for the purposes of Sections 10.1(iv) 10.1(x)).

“Material Adverse Effect”: (a) a change in the business, property, operations or financial condition of the Borrower and its Subsidiaries taken as a whole that could reasonably be expected to materially and adversely affect the Borrower’s ability to perform its obligations under the Loan Documents or (b) a material adverse effect on (i) the validity or enforceability of this Agreement or any of the other Loan Documents or (ii) the rights and remedies of the Administrative Agent and the Lenders, taken as a whole, under this Agreement or any other Loan Document.

“Materials of Environmental Concern”: any gasoline or petroleum (including crude oil or any fraction thereof) or petroleum products or any hazardous or toxic substances, materials or wastes, defined or regulated as such in or under any Environmental Law, including asbestos, polychlorinated biphenyls and urea-formaldehyde insulation.

“Maturity Date”: (a) with respect to the 364-Day Tranche Loans, the 364-Day Tranche Maturity Date, and (b) with respect to the 18-Month Tranche Loans, the 18-Month Tranche Maturity Date.

“Moody’s”: Moody’s Investors Service, Inc.

“Mortgaged Property”: as defined in the FMB Indenture.

“Multiemployer Plan”: a plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Net Cash Proceeds”: with respect to any Debt Issuance, the excess, if any, of (i) cash actually received by the Borrower or its Subsidiaries in connection with such incurrence, issuance, offering or placement over (ii) the underwriting discounts and commissions and other fees and expenses incurred by the Borrower or its Subsidiaries in connection with such incurrence, issuance, offering or placement.

“Net Tangible Assets”: the total amount of the Borrower’s assets determined on a consolidated basis in accordance with GAAP as of the last day of the most recently ended fiscal quarter for which financial statements have been delivered under Section 6.1, less (a) the sum of the Borrower’s consolidated current liabilities determined in accordance with GAAP, and (b) the amount of the Borrower’s consolidated assets classified as intangible assets, determined in accordance with GAAP.

“Non-Recourse Debt”: Indebtedness of the Borrower or any of its Significant Subsidiaries that is incurred in connection with the acquisition, construction, sale, transfer or other Disposition of specific assets, to the extent recourse, whether contractual or as a matter of law, for non-payment of such Indebtedness is limited (a) to such assets, or (b) if such assets are (or are to be) held by a Subsidiary formed solely for such purpose, to such Subsidiary or the Capital Stock of such Subsidiary.

“Notes”: as defined in Section 2.14(f).

“NYFRB”: the Federal Reserve Bank of New York.

“NYFRB Rate”: for any day, the greater of (a) the Federal Funds Effective Rate in effect on such day and (b) the Overnight Bank Funding Rate in effect on such day (or for any day that is not a Business Day, for the immediately preceding Business Day); provided that if none of such rates are published for any day that is a Business Day, the term “NYFRB Rate” means the rate for a federal funds transaction quoted at 11:00 a.m. (New York City time) on such day received by the Administrative Agent from a federal funds broker of recognized standing selected by it; provided, further, that if any of the aforesaid rates as so determined would be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“NYFRB’s Website”: the website of the NYFRB at http://www.newyorkfed.org, or any successor source.

“Obligations”: the unpaid principal of and interest on (including, without limitation, interest accruing after the maturity of the Loans and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to the Borrower, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) the Loans and all other obligations and liabilities of the Borrower to the Administrative Agent or to any Lender, whether direct or

indirect, absolute or contingent, due or to become due, or now existing or hereafter incurred, which may arise under, out of, or in connection with, this Agreement, any other Loan Document or any other document made, delivered or given in connection herewith or therewith, whether on account of principal, interest, reimbursement obligations, fees, indemnities, costs, expenses (including, without limitation, all fees, charges and disbursements of counsel to the Administrative Agent or to any Lender that are required to be paid by the Borrower pursuant hereto) or otherwise.

“OECD”: the countries constituting the “Contracting Parties” to the Convention on the Organisation For Economic Co-operation and Development, as such term is defined in Article 4 of such Convention.

“Other Connection Taxes”: with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Other Taxes”: all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 2.19).

“Overnight Bank Funding Rate”: for any day, the rate comprised of both overnight federal funds and overnight Eurodollar borrowings by U.S.-managed banking offices of depository institutions, as such composite rate shall be determined by the NYFRB as set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as an overnight bank funding rate.

“Participant”: as defined in Section 10.6(c).

“Participant Register”: as defined in Section 10.6(c)(iii).

“Patriot Act”: as defined in Section 10.16.

“Payment Recipient”: as defined in Section 9.13(a).

“PBGC”: the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA (or any successor).

“PCG”: as defined in the first recital paragraph.

“PCG Commitment Letter”: that certain Commitment Letter dated as of October 4, 2019 among PG&E Corporation, as the borrower, Pacific Gas and Electric Company and the commitment parties from time to time party thereto, as amended, modified or supplemented from time to time prior to the date hereof.

“PCG Revolving Credit Agreement”: that certain Credit Agreement dated as of the Effective Date, among PCG, the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent.

“Percentage”: as to any Lender at any time with respect to a Tranche, the percentage which the aggregate principal amount of such Lender’s Loans then outstanding constitutes of the aggregate principal amount of the Loans then outstanding with respect to such Tranche.

“Permitted Refinancing”: with respect to any Indebtedness (the “Refinanced Indebtedness”), any extension, refinancing, refunding or replacement thereof with Indebtedness provided that (i) the amount of such Indebtedness does not exceed the aggregate principal amount of the Refinanced Indebtedness, plus any premium, interest, fee or expenses payable in connection therewith, (ii) the final maturity date of such Indebtedness is no earlier than the maturity date of the Refinanced Indebtedness, and (iii) the weighted average life to maturity of such Indebtedness is not shorter than the weighted average life to maturity of the Refinanced Indebtedness.

“Person”: an individual, partnership, corporation, limited liability company, business trust, joint stock company, trust, unincorporated association, joint venture, Governmental Authority or other entity of whatever nature.

“Plan”: at a particular time, any employee benefit plan that is covered by ERISA and in respect of which the Borrower or a Commonly Controlled Entity is (or, if such plan were terminated at such time, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

“Plan of Reorganization”: as defined in the second recital paragraph.

“Platform”: as defined in Section 10.2(d).

“Prime Rate”: the rate of interest last quoted by The Wall Street Journal as the “Prime Rate” in the U.S. or, if The Wall Street Journal ceases to quote such rate, the highest per annum interest rate published by the Federal Reserve Board in Federal Reserve Statistical Release H.15 (519) (Selected Interest Rates) as the “bank prime loan” rate or, if such rate is no longer quoted therein, any similar rate quoted therein (as determined by the Administrative Agent) or in any similar release by the Federal Reserve Board (as determined by the Administrative Agent). Each change in the Prime Rate shall be effective from and including the date such change is publicly announced or quoted as being effective.

“PTE”: a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“QFC”: the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

“QFC Credit Support” in Section 10.19.

“Qualified Securitization Bond Issuer”: a Subsidiary of the Borrower formed and operating solely for the purpose of (a) purchasing and owning property created under a “financing order” (as such term is defined in the California Public Utilities Code) or similar order issued by the CPUC, (b) issuing such securities pursuant to such order, (c) pledging its interests in such property to secure such securities and (d) engaging in activities ancillary to those described in (a), (b) and (c).

“Rating”: each rating announced by S&P and Moody’s in respect of the Borrower’s senior secured debt.

“Recipient”: the Administrative Agent or any Lender.

“Register”: as defined in Section 10.6(b).

“Regulation U”: Regulation U of the Federal Reserve Board as in effect from time to time.

“Related Parties”: with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

“Relevant Governmental Body”: the Federal Reserve Board or the NYFRB, or a committee officially endorsed or convened by the Federal Reserve Board or the NYFRB or, in each case, any successor thereto.

“Removal Effective Date”: as defined in Section 9.9(b).

“Reportable Event”: any of the events set forth in Section 4043(c) of ERISA, other than those events as to which the thirty-day notice period is waived under subsections .27, .28, .29, .30, .31, .32, .34 or .35 of PBGC Reg. § 4043.

“Required Lenders”: at any time, the holders of more than 50% of the aggregate Loans then outstanding. The Loans of any Defaulting Lender shall be disregarded in determining Required Lenders at any time.

“Requirement of Law”: as to any Person, the Articles of Incorporation and By-Laws or other organizational or governing documents of such Person, and any law, treaty, rule or regulation or determination of an arbitrator or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject.

“Resignation Effective Date”: as defined in Section 9.9(a).

“Resolution Authority”: with respect to any EEA Financial Institution, an EEA Resolution Authority and, with respect to any UK Financial Institution, a UK Resolution Authority.

“Responsible Officer”: the chief executive officer, president, chief financial officer, treasurer or assistant treasurer of the Borrower, but in any event, with respect to financial matters, the chief financial officer, treasurer or assistant treasurer of the Borrower.

“S&P”: Standard & Poor’s Global Ratings, a division of S&P Global Inc., and any successor thereto.

“Sanctions”: as defined in Section 4.15.

“SEC”: the Securities and Exchange Commission, any successor thereto and any analogous Governmental Authority.

“Securitized Bonds”: without duplication, securities, however denominated, that are (i) issued by a Qualified Securitization Bond Issuer, (ii) secured by or otherwise payable from charges authorized by the financing order referred to in clause (a) of the definition of “Qualified Securitization Bond Issuer,” and (iii) non-recourse to the Borrower or any of its Subsidiaries (other than the issuer of such securities).

“Senior Bonds”: (i) with respect to the 364-Day Tranche Loans, that certain First Mortgage Bond in the aggregate principal amount of $1,500,000,000 and (ii) with respect to the 18-Month Tranche Loans, those certain First Mortgage Bonds in the aggregate combined principal amount of $1,500,000,000, in each case, issued to the Administrative Agent pursuant to the Supplemental Indenture.

“Significant Subsidiary”: as defined in Article 1, Rule 1-02(w) of Regulation S-X of the Exchange Act as of the Effective Date, provided that notwithstanding the foregoing, no special purpose finance subsidiary, no A/R Securitization Subsidiary (or Subsidiaries of any A/R Securitization Subsidiary) nor any Qualified Securitization Bond Issuer (or Subsidiaries of any Qualified Securitization Bond Issuer) shall constitute a Significant Subsidiary. Unless otherwise qualified, all references to a “Significant Subsidiary” or to “Significant Subsidiaries” in this Agreement shall refer to a “Significant Subsidiary” or “Significant Subsidiaries” of the Borrower.

“Single Employer Plan”: any Plan that is covered by Title IV of ERISA, but that is not a Multiemployer Plan.

“SOFR”: a rate per annum equal to the secured overnight financing rate for such Business Day published by the NYFRB (or a successor administrator of the secured overnight financing rate) on the NYFRB’s Website (or any successor source for the secured overnight financing rate identified as such by the administrator of the secured overnight financing rate from time to time).

“Solvent”: with respect to the Borrower and its Subsidiaries, on a consolidated basis, that as of the date of determination, (i) the fair value of the assets of the Borrower and its Subsidiaries, on a consolidated basis, at a fair valuation on a going concern basis, exceeds, on a consolidated basis, their debts and liabilities, subordinated, contingent or otherwise, (ii) the present fair saleable value of the property of the Borrower and its Subsidiaries, on a consolidated and going concern basis, is greater than the amount that will be required to pay the probable liability, on a consolidated basis, of their debts and other liabilities, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured in the ordinary course of business, (iii) the Borrower and its Subsidiaries, on a consolidated basis, are able to pay their debts and liabilities, subordinated, contingent or otherwise, as such liabilities become absolute and matured in the ordinary course of business, (iv) the Borrower and its Subsidiaries are not engaged in businesses, and are not about to engage in businesses for which they have unreasonably small capital. For purposes of this definition, the amount of any contingent liability at any time shall be computed as the amount that, in light of all the facts and circumstances existing as of the Effective Date, would reasonably be expected to become an actual and matured liability.

“Specified Exchange Act Filings”: the Borrower’s Form 10-K annual report for the year ended December 31, 2020 and each and all of the Form 10-Qs and Form 8-Ks (and to the extent applicable proxy statements) filed by the Borrower or PCG with the SEC after December 31, 2020 and prior to the date that is one Business Day before the Amendment No. 1 Effective Date.

“Specified Material Adverse Effect”: any occurrence, fact, change, event, effect, violation, penalty, inaccuracy or circumstance that, individually or in the aggregate with any such other results, occurrences, facts, changes, events, effects, violations, penalties, inaccuracies, or circumstances, (i) would have or would reasonably be expected to have a material adverse effect on the business, operations, assets, liabilities, capitalization, financial performance, financial condition or results of operations, in each case, of PCG

and the Borrower, taken as a whole, or (ii) would reasonably be expected to prevent or materially delay the ability of the Borrower to consummate the transactions contemplated by this Agreement or perform its obligations hereunder; provided, however, that none of the following results, occurrences, facts, changes, events, effects, violations, penalties, inaccuracies or circumstances shall constitute or be taken into account in determining whether a Specified Material Adverse Effect has occurred, is continuing or would reasonably be expected to occur: (A) [reserved], (B) results, occurrences, facts, changes, events, violations, inaccuracies or circumstances affecting (1) the electric or gas utility businesses in the United States generally or (2) the economy, credit, financial, capital or commodity markets, in the United States or elsewhere in the world, including changes in interest rates, monetary policy or inflation, (C) changes or prospective changes in law (other than any law or regulation of California or the United States that is applicable to any electrical utility) or in GAAP or accounting standards, or any changes or prospective changes in the interpretation or enforcement of any of the foregoing, (D) any decline in the market price, or change in trading volume, of any securities of PCG, (E) any failure to meet any internal or public projections, forecasts, guidance, estimates, milestones, credit ratings, budgets or internal or published financial or operating predictions of revenue, earnings, cash flow or cash position, (F) [reserved], and (G) one or more wildfires, occurring on or after January 1, 2020, that destroys or damages fewer than 500 dwellings or commercial structures in the aggregate (it being understood that (I) the exceptions in clauses (D) and (E) shall not prevent or otherwise affect a determination that the underlying cause of any such change, decline or failure referred to therein is a Specified Material Adverse Effect, and (II) a Specified Material Adverse Effect shall include the occurrence of one or more wildfires on or after January 1, 2020 destroying or damaging at least 500 dwellings or commercial structures within PCG’s service area at a time when the portion of PCG’s system at the location of such wildfire was not successfully de-energized).

“Standard A/R Securitization Obligations”: representations, warranties, covenants, indemnities, repurchase obligations, servicing obligations, guarantees, intercompany notes and obligations relating to contributions of A/R Securitization Assets to an A/R Securitization Subsidiary and other obligations entered into by the Borrower or any of its Subsidiaries which are reasonably customary in A/R Securitization Transactions.

“Subsidiary”: as to any Person, a corporation, partnership, limited liability company or other entity of which shares of stock or other ownership interests having ordinary voting power (other than stock or such other ownership interests having such power only by reason of the happening of a contingency) to elect a majority of the board of directors or other managers of such corporation, partnership or other entity are at the time owned, or the management of which is otherwise controlled, directly or indirectly through one or more intermediaries, or both, by such Person. Unless otherwise qualified, all references to a “Subsidiary” or to “Subsidiaries” in this Agreement shall refer to a Subsidiary or Subsidiaries of the Borrower.

“Supplemental Indenture”: with respect to those certain First Mortgage Bonds in the aggregate principal amount of $3,000,000,000 issued to the Administrative Agent, the Supplemental Indenture, dated as of the Effective Date, by and between the Borrower and the Indenture Trustee.

“Supported QFC”: as defined in Section 10.19.

“Swap Agreement”: any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or

economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or any of its Subsidiaries shall be a “Swap Agreement”.

“Syndication Agents”: as defined on the cover hereto.

“Taxes”: all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Term SOFR”: for the applicable corresponding tenor, the forward-looking term rate based on SOFR that has been selected or recommended by the Relevant Governmental Body.

“Tranche”: (i) the 364-Day Tranche Commitments or the 364-Day Tranche Loans or (ii) the 18-Month Tranche Commitments or the 18-Month Tranche Loans (or, with respect to the 18-Month Tranche Loans, the 18-Month Tranche Loans (Tranche A) and the 18-Month Tranche Loans (Tranche B)).

“Transferee”: any Assignee or Participant.

“Type”: as to any Loan, its nature as an ABR Loan or a Eurodollar Loan.

“UK Financial Institution”: any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority)) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority”: the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“United States” or “U.S.”: the United States of America.

“U.S. Person”: any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Code.

“U.S. Special Resolution Regime”: as defined in Section 10.19.

“U.S. Tax Compliance Certificate”: as defined in Section 2.16(e)(ii)(B)(III).

“Utility Commitment Letter”: that certain Commitment Letter dated as of October 4, 2019 among Pacific Gas and Electric Company, as the borrower, PG&E Corporation and the commitment parties from time to time party thereto, as amended, modified or supplemented from time to time prior to the date hereof.

“Utility Revolving Credit Agreement”: that certain Credit Agreement dated as of the Effective Date, among the Borrower, the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent.

“Withdrawal Liability”: any liability to a Multiemployer Plan as a result of a complete or partial withdrawal by the Borrower or any Commonly Controlled Entity from such Multiemployer Plan, as such terms are defined in Title IV of ERISA.

“Write-Down and Conversion Powers”: (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the applicable Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to any UK Resolution Authority, any powers of such UK Resolution Authority under the applicable Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

1.1Other Definitional Provisions and Interpretative Provisions.

(a)Unless otherwise specified therein, all terms defined in this Agreement shall have the defined meanings when used in the other Loan Documents or any certificate or other document made or delivered pursuant hereto or thereto.

(b)As used herein and, except as otherwise provided therein, in the other Loan Documents, and any certificate or other document made or delivered pursuant hereto or thereto, (i) accounting terms relating to the Borrower and its Significant Subsidiaries defined in Section 1.1 and accounting terms partly defined in Section 1.1, to the extent not defined, shall have the respective meanings given to them under GAAP, (ii) the words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”, (iii) the word “incur” shall be construed to mean incur, create, issue, assume or become liable in respect of (and the words “incurred” and “incurrence” shall have correlative meanings), (iv) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, Capital Stock, securities, revenues, accounts, leasehold interests and contract rights, and (v) references to agreements or other Contractual Obligations shall, unless otherwise specified, be deemed to refer to such agreements or Contractual Obligations as amended, supplemented, restated or otherwise modified from time to time.

(c)The words “hereof”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section, Schedule and Exhibit references are to this Agreement unless otherwise specified.

(d)The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

(e)The Borrower shall not be required to perform, nor shall it be required to guarantee the performance of, any of the affirmative covenants set

forth in Section 6 that apply to any of its Significant Subsidiaries nor shall any of the Borrower’s Significant Subsidiaries be required to perform, nor shall any of such Significant Subsidiaries be required to guarantee the performance of, any of the Borrower’s affirmative covenants set forth in Section 6 or any of the affirmative covenants set forth in Section 6 that apply to any other Significant Subsidiary; provided, that nothing in this Section 1.2(e) shall prevent the occurrence of a Default or an Event of Default arising out of the Borrower’s failure to cause any Significant Subsidiary to comply with the provisions of this Agreement applicable to such Significant Subsidiary.

(f)Notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to any change in accounting for leases pursuant to GAAP resulting from the implementation of Financial Accounting Standards Board ASU No. 2016-02, Leases (Topic 842), to the extent such adoption would require treating any lease (or similar arrangement conveying the right to use) as a capital lease where such lease (or similar arrangement) would not have been required to be so treated under GAAP as in effect on December 31, 2015.

1.2Divisions. For all purposes under the Loan Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized and acquired on the first date of its existence by the holders of its Capital Stock at such time.

1.3Interest Rates; LIBOR Notification. The interest rate on Eurodollar Loans is determined by reference to the Eurodollar Base Rate, which is derived from the London interbank offered rate (“LIBOR”). LIBOR is intended to represent the rate at which contributing banks may obtain short-term borrowings from each other in the London interbank market. On March 5, 2021, the FCA publicly announced that: (a) immediately after December 31, 2021, publication of all seven euro LIBOR settings, all seven Swiss Franc LIBOR settings, the spot next, 1-week, 2-month and 12-month Japanese Yen LIBOR settings, the overnight, 1-week, 2-month and 12-month British Pound Sterling LIBOR settings, and the 1-week and 2-month U.S. Dollar LIBOR settings will permanently cease; immediately after June 30, 2023, publication of the overnight and 12-month U.S. Dollar LIBOR settings will permanently cease; immediately after December 31, 2021, the 1-month, 3-month and 6-month Japanese Yen LIBOR settings and the 1-month, 3-month and 6-month British Pound Sterling LIBOR settings will cease to be provided or, subject to consultation by the FCA, be provided on a changed methodology (or “synthetic”) basis and no longer be representative of the underlying market and economic reality they are intended to measure and that representativeness will not be restored; and immediately after June 30, 2023, the 1-month, 3- month and 6-month U.S. Dollar LIBOR settings will cease to be provided or, subject to the FCA’s consideration of the case, be provided on a synthetic basis and no longer be representative of the underlying market and economic reality they are intended to measure and that representativeness will not be restored. There is no assurance that dates announced by the FCA will not change or that the administrator of LIBOR and/or regulators will not take further

action that could impact the availability, composition, or characteristics of LIBOR or the currencies and/or tenors for which LIBOR is published. Each party to this agreement should consult its own advisors to stay informed of any such developments. Public and private sector industry initiatives are currently underway to identify new or alternative reference rates to be used in place of LIBOR. Upon the occurrence of a Benchmark Transition Event or an Early Opt-In Election, Section 2.13(b) and (c) provide the mechanism for determining an alternative rate of interest. The Administrative Agent will promptly notify the Borrower, pursuant to Section 2.13(e), of any change to the reference rate upon which the interest rate on Eurodollar Loans is based. However, the Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to, the administration, submission or any other matter related to LIBOR or other rates in the definition of “Eurodollar Base Rate” or with respect to any alternative or successor rate thereto, or replacement rate thereof (including, without limitation, (i) any such alternative, successor or replacement rate implemented pursuant to Section 2.13(b) or (c), whether upon the occurrence of a Benchmark Transition Event or an Early Opt-In Election, and (ii) the implementation of any Benchmark Replacement Conforming Changes pursuant to Section 2.13(d)), including without limitation, whether the composition or characteristics of any such alternative, successor or replacement reference rate will be similar to, or produce the same value or economic equivalence of, the Eurodollar Base Rate or have the same volume or liquidity as did the London interbank offered rate prior to its discontinuance or unavailability.

Section 13.AMOUNT AND TERMS OF THE TERM LOANS

1.1Loans.

(a)Subject to the terms and conditions set forth herein, each 364-Day Tranche Lender (severally and not jointly) agrees to make a term loan (the “364-Day Tranche Loans”) to the Borrower in Dollars on the Effective Date in an amount equal to such 364-Day Tranche Lender’s 364-Day Tranche Commitment. Loans under the 364-Day Tranche may be ABR Loans or Eurodollar Loans, as further provided herein. 364-Day Tranche Loans borrowed under this Section 2.1(a) and paid or prepaid may not be reborrowed.

(b)Subject to the terms and conditions set forth herein, each 18-Month Tranche Lender (severally and not jointly) agrees to make a term loan (the “18-Month Tranche Loans”) to the Borrower in Dollars on the Effective Date in an aggregate amount equal to the amount of such 18-Month Tranche Lender’s 18-Month Tranche Commitment. Loans under the 18-Month Tranche may be ABR Loans or Eurodollar Rate Loans, as further provided herein. 18-Month Tranche Loans borrowed under this Section 2.1(b)2.1(b) and paid or prepaid may not be reborrowed. As of the Amendment No. 1 Effective Date, a portion of the 18-Month Tranche Loans in an aggregate amount of $1,315,735,897.44 (the “18-Month Tranche Loans (Tranche A)”) shall have an 18-Month Tranche Maturity Date of October 1, 2022 and a portion of the 18-Month Tranche Loans in an aggregate amount of $184,264,102.56 (the “18-Month Tranche Loans (Tranche B)”) shall have an 18-Month Tranche Maturity Date of January 1, 2022. As of the Amendment No. 2 Effective Date, the 18-Month Tranche Loans (Tranche B) shall have an 18-Month Tranche Maturity Date of October 1, 2022.

1.2Procedures for Borrowing. The Borrower may borrow the Loans on the Effective Date (so long as the Effective Date is a Business Day), provided that the Borrower shall give the Administrative Agent irrevocable notice (which notice must be received by the Administrative Agent (a) prior to 12:00 Noon, New York City time, three Business Days prior to the Effective Date, in the case of Eurodollar Loans, or (b) prior to 1:00 P.M., New York City time, one Business Day prior to the Effective Date, in the case of ABR Loans) specifying (i) the amount and Type of Loans to be borrowed on the Effective Date and (ii) in the case of Eurodollar Loans, the respective amounts of each such Type of Loan and the respective lengths of the initial Interest Period therefor. Upon receipt of any such notice from the Borrower, the Administrative Agent shall promptly notify each Lender thereof. Each Lender will make the amount of its pro rata share of each borrowing available to the Administrative Agent for the account of the Borrower at the Funding Office prior to 10:00 A.M., New York City time, on the Effective Date requested by the Borrower in funds immediately available to the Administrative Agent. Such borrowing will then be made available to the Borrower by the Administrative Agent crediting the account of the Borrower on the books of such office with the aggregate of the amounts made available to the Administrative Agent by the Lenders and in like funds as received by the Administrative Agent

1.3[Reserved].

1.4[Reserved].

1.5[Reserved].

1.6Fees, Etc.

(a)The Borrower agrees to pay to the Administrative Agent, for the account of each Lender (other than a Defaulting Lender to the extent provided in Section 2.20), any fees payable in the amounts and at the times separately agreed upon between the Borrower and the Lenders.

(b)The Borrower agrees to pay to the Administrative Agent the fees in the amounts and on the dates as set forth in any written, duly executed fee agreements with the Administrative Agent and to perform any other obligations contained therein.

(c)On June 1, 2022, the Borrower agrees to pay to the Administrative Agent, for the account of each Lender that holds any 18-Month Tranche Loans (Tranche A) outstanding on such date, a fee equal to 0.075% of the principal amount of such Loans.

(a)On January 1, 2022, the Borrower agrees to pay to the Administrative Agent, for the account of each Lender that holds any 18-Month Tranche Loans (Tranche B) outstanding on such date, a fee equal to 0.075% of the principal amount of such Loans.

1.7Termination of Commitments. The Commitments shall automatically terminate in full on the Effective Date after the proceeds of the Loans have been made available to the Borrower.

1.8Prepayments.

(a)Optional. The Borrower may at any time and from time to time prepay the Loans, in whole or in part, without premium or penalty, upon irrevocable notice delivered to the Administrative Agent no later than 12:00 Noon, New York City time, three Business Days prior thereto, in the case of Eurodollar Loans, and no later than 2:00 p.m., New York City time, one Business Day prior thereto, in the case of ABR Loans, which notice shall specify the date and amount of prepayment and whether the prepayment is of Eurodollar Loans or ABR Loans. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof. If any such notice is given, the amount specified in such notice shall be due and payable on the date specified therein, together with accrued interest to such date on the amount prepaid. Partial prepayments of Loans shall be in an aggregate principal amount of $1,000,000 or a whole multiple of $500,000 in excess thereof. Notwithstanding the foregoing, any notice of prepayment delivered in connection with any refinancing of all of the Loans with the proceeds of such refinancing or of any other incurrence of Indebtedness or the occurrence of some other identifiable event or condition, may be, if expressly so stated to be, contingent upon the consummation of such refinancing or incurrence or occurrence of such other identifiable event or condition and may be revoked by the Borrower, subject to compliance with the obligations under Section 2.17 in connection with any such revocation, in the event such contingency is not met. Each prepayment of Loans under this clause (a) shall be applied to the prepayment in full of the aggregate principal amount and any accrued but unpaid interest with respect to the 364-Day Tranche Loans before being applied to prepay the aggregate principal amount and any accrued but unpaid interest with respect to the 18-Month Tranche Loans and shall be accompanied by accrued interest and fees on the amount prepaid to the date fixed for prepayment, plus, in the case of any Eurodollar Loans that are prepaid on any day other than the last day of the Interest Period applicable to it, the Borrower shall pay any amounts due to the Lenders as a result thereof pursuant to Section 2.17.

(b)Mandatory. So long as (i) the commitments in respect of each of the Bridge Facilities have been terminated without the funding of any loans thereunder or (ii) the loans and any accrued interest, fees and other obligations under the Bridge Facilities have been paid in full, in the event that the Borrower or any of its Subsidiaries receives any Net Cash Proceeds arising from any Debt Issuance, then the Borrower shall prepay the Loans hereunder in an amount equal to 100% of such Net Cash Proceeds not later than five (5) Business Days following the receipt by the Borrower or such Subsidiary of such Net Cash Proceeds. The Borrower shall promptly (and not later than five (5) Business Days following receipt thereof) notify the Administrative Agent of the receipt by the Borrower or any Subsidiary, as applicable, of such Net Cash Proceeds and such notice shall be accompanied by a reasonably detailed calculation of the Net Cash Proceeds. Each prepayment of Loans under this clause (b) shall be applied to the prepayment in full of the aggregate principal amount and any accrued but unpaid interest with respect to the 364-Day Tranche Loans before being applied to prepay the aggregate principal amount and any accrued but unpaid interest with respect to the 18-Month Tranche Loans and shall be accompanied by accrued interest and fees on the amount prepaid to the date fixed for prepayment, plus, in the case of any Eurodollar Loans that are prepaid on any day other than the last day of the Interest Period applicable to it, the Borrower shall pay any amounts due to the Lenders as a result thereof pursuant to Section 2.17.

1.9Conversion and Continuation Options.

(a)The Borrower may elect from time to time to convert Eurodollar Loans to ABR Loans by giving the Administrative Agent prior irrevocable notice of such election no later than 12:00 Noon, New York City time, on the Business Day preceding the proposed conversion date, provided that any such conversion of Eurodollar Loans may only be made on the last day of an Interest Period with respect thereto. The Borrower may elect from time to time to convert ABR Loans to Eurodollar Loans by giving the Administrative Agent prior irrevocable notice of such election no later than 12:00 Noon, New York City time, on the third Business Day preceding the proposed conversion date (which notice shall specify the length of the initial Interest Period therefor), provided that no ABR Loan may be converted into a Eurodollar Loan when any Event of Default has occurred and is continuing and the Required Lenders have determined in their sole discretion not to permit such conversions. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.

(b)Any Eurodollar Loan may be continued as such upon the expiration of the then current Interest Period with respect thereto by the Borrower giving irrevocable notice to the Administrative Agent, in accordance with the applicable provisions of the defined term “Interest Period”, of the length of the next Interest Period to be applicable to such Loans, provided that no Eurodollar Loan may be continued as such when any Event of Default has occurred and is continuing and the Required Lenders have determined in their sole discretion not to permit such continuations; provided, further, that if the Borrower shall fail to give any required notice as described above in this paragraph, subject to the preceding proviso, such Loans shall be automatically continued as Eurodollar Loans with an Interest Period of one month on the last day of such then expiring Interest Period.Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.

1.10Limitations on Eurodollar Tranches. Notwithstanding anything to the contrary in this Agreement, all borrowings, conversions and continuations of Eurodollar Loans and all selections of Interest Periods shall be in such amounts and be made pursuant to such elections so that (a) after giving effect thereto, the aggregate principal amount of the Eurodollar Loans comprising each Eurodollar Tranche shall be equal to $1,000,000 or a whole multiple of $500,000 in excess thereof and (b) no more than 5 Eurodollar Tranches shall be outstanding at any one time.

1.11Interest Rates and Payment Dates.

(a)Each Eurodollar Loan shall bear interest for each day during each Interest Period with respect thereto at a rate per annum equal to the Eurodollar Rate determined for such day plus the Applicable Margin.

(b)Each ABR Loan shall bear interest at a rate per annum equal to the ABR plus the Applicable Margin.

(c)(i) If all or a portion of the principal amount of the Loans shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a default rate per annum equal to the rate that would otherwise be applicable thereto pursuant to the foregoing

provisions of this Section plus 2% and (ii) if all or a portion of any interest payable on the Loans or any other fee payable in connection herewith (excluding any expenses or other indemnity) shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a default rate per annum equal to the rate then applicable to ABR Loans plus 2%, in each case, with respect to clauses (i) and (ii) above, from the date of such non-payment until such amount is paid in full (as well after as before judgment).

(d)Interest shall be payable in arrears on each Interest Payment Date, provided that interest accruing pursuant to Section 2.11(c) shall be payable from time to time on demand.

(e)The amount of each interest payment received by the Administrative Agent under the applicable Senior Bond shall be deemed to be a payment of interest payable by the Borrower hereunder and shall reduce, dollar-for-dollar, the amount of interest then owing by the Borrower hereunder.

1.12Computation of Interest and Fees.

(a)Interest and fees payable pursuant hereto shall be calculated on the basis of a 360-day year for the actual days elapsed, except that, with respect to ABR Loans the rate of interest on which is calculated on the basis of ABR, the interest thereon shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed. The Administrative Agent shall as soon as practicable notify the Borrower and the relevant Lenders of each determination of a Eurodollar Rate. Any change in the interest rate on a Loan resulting from a change in the ABR or the Eurocurrency Reserve Requirements shall become effective as of the opening of business on the day on which such change becomes effective. The Administrative Agent shall as soon as practicable notify the Borrower and the relevant Lenders of the effective date and the amount of each such change in interest rate.

(b)Each determination of an interest rate by the Administrative Agent pursuant to any provision of this Agreement shall constitute prima facie evidence of such amounts. The Administrative Agent shall, at the request of the Borrower or any Lender, deliver to the Borrower or such Lender a statement showing the quotations used by the Administrative Agent in determining any interest rate pursuant to Section 2.11(a).

1.13Inability to Determine Interest Rate.

(a)Subject to clauses (b), (c), (d), (e), (f) and (g) of this Section 2.13, if prior to the commencement of any Interest Period for a Eurodollar Loan:

Section 14.the Administrative Agent determines (which determination shall be conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the Eurodollar Rate or the Eurodollar Base Rate, as applicable (including because the Eurodollar Screen Rate is not available or published on a current basis) for such Interest Period, provided that no Benchmark Transition Event shall have occurred at such time; or

Section 15.the Administrative Agent is advised by the Required Lenders that the Eurodollar Rate or the Eurodollar Base Rate, as applicable, for such Interest Period

will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in the applicable borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone, telecopy or electronic mail as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (A) any notice from the Borrower to the Administrative Agent that requests the conversion of any Loans to, or continuation of any Loans as, a Eurodollar borrowing shall be ineffective and (B) if any borrowing notice delivered pursuant to Section 2.2 requests a borrowing of Eurodollar Loans, such borrowing shall be made as an ABR Loan; provided that if the circumstances giving rise to such notice affect only one Type of borrowings, then the other Type of borrowings shall be permitted.

(a)Replacing USD LIBOR. Notwithstanding anything to the contrary herein or in any other Loan Document, on March 5, 2021 the Financial Conduct Authority (“FCA”), the regulatory supervisor of the Eurodollar Base Rate’s administrator (“IBA”), announced in a public statement the future cessation or loss of representativeness of overnight/Spot Next, 1-week, 1-month, 3-month, 6-month and 12-month Eurodollar Base Rate tenor settings. On the earlier of (i) the date that all Available Tenors of the Eurodollar Base Rate have either permanently or indefinitely ceased to be provided by IBA or have been announced by the FCA pursuant to public statement or publication of information to be no longer representative and (ii) the Early Opt-in Effective Date, if the then-current Benchmark is the Eurodollar Base Rate, the Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Loan Document in respect of any setting of such Benchmark on such day and all subsequent settings without any amendment to, or further action or consent of any other party to this Agreement or any other Loan Document. If the Benchmark Replacement is Daily Simple SOFR, all interest payments will be payable on a monthly basis.

(b)Replacing Future Benchmarks. Upon the occurrence of a Benchmark Transition Event, the Benchmark Replacement will replace the then-current Benchmark for all purposes hereunder and under any Loan Document in respect of any Benchmark setting at or after 5:00 p.m. on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Required Lenders. Upon the occurrence of a Benchmark Transition Event, the Borrower may revoke any request for a borrowing of, conversion to or continuation of Loans to be made, converted or continued that would bear interest by reference to such Benchmark until the Borrower’s receipt of notice from the Administrative Agent that a Benchmark Replacement has replaced such Benchmark, and, failing that, the Borrower will be deemed to have converted any such request into a request for a borrowing of or conversion to ABR Loans. During the period referenced in the foregoing sentence, the component of ABR based upon the Benchmark will not be used in any determination of ABR.

(c)Benchmark Replacement Conforming Changes. In connection with the implementation and administration of a Benchmark Replacement, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement.

(d)Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (i) the implementation of any Benchmark Replacement and (ii) the effectiveness of any Benchmark Replacement Conforming Changes. For the avoidance of doubt, any notice required to be delivered by the Administrative Agent as set forth in this Section 2.13 may be provided, at the option of the Administrative Agent (in its sole discretion), in one or more notices and may be delivered together with, or as part of any amendment which implements any Benchmark Replacement or Benchmark Replacement Conforming Changes. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party hereto, except, in each case, as expressly required pursuant to this Section 2.13.

(e)Unavailability of Tenor of Benchmark. At any time (including in connection with the implementation of a Benchmark Replacement), (i) if the then-current Benchmark is a term rate (including Term SOFR or Eurodollar Base Rate), then the Administrative Agent may remove any tenor of such Benchmark that is unavailable or non-representative for Benchmark (including Benchmark Replacement) settings and (ii) the Administrative Agent may reinstate any such previously removed tenor for Benchmark (including Benchmark Replacement) settings.

(f)Disclaimer. The Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to (i) the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of “Eurodollar Rate” or “Eurodollar Base Rate” or with respect to any alternative or successor rate thereto, or replacement rate thereof (including, without limitation any Benchmark Replacement implemented hereunder), (ii) the composition or characteristics of any Benchmark Replacement, including whether it is similar to, or produces the same value or economic equivalence to the Eurodollar Base Rate (or any other Benchmark) or have the same volume or liquidity as did the Eurodollar Base Rate (or any other Benchmark), (iii) any actions or use of its discretion or other decisions or determinations made with respect to any matters covered by this Section 2.13 including, without limitation, whether or not a Benchmark Transition Event has occurred, the removal or lack thereof of unavailable or non-representative tenors, the implementation or lack thereof of any Benchmark Replacement Conforming Changes, the delivery or non-delivery of any notices required by clause (e) above or otherwise in accordance herewith, and (iv) the effect of any of the foregoing provisions of this Section 2.13.

1.2Pro Rata Treatment and Payments; Notes.

(a)[Reserved].

(b)Each payment (including each prepayment) by the Borrower on account of principal of and interest on the Loans (other than, for the avoidance of doubt, payment in full of all principal and interest due with respect to the 18-Month Tranche Loans (Tranche B) on or prior to the 18-Month Tranche Maturity Date for such Loans) shall be made pro rata (i) in the case of the 364-Day Tranche Loans, according to the respective outstanding principal amounts of the 364-Day Tranche Loans then held by the 364-Day Tranche Lenders and (ii) in the case of the 18-Month Tranche Loans, according to the respective outstanding principal amounts of the 18-Month Tranche Loans then held by the 18-Month Tranche Lenders.

(c)Notwithstanding anything to the contrary herein, all payments (including prepayments) to be made by the Borrower hereunder, whether on account of principal, interest, fees or otherwise, shall be made without setoff or counterclaim and shall be made prior to 4:00 P.M., New York City time, on the due date thereof to the Administrative Agent, for the account of the Lenders, as applicable, at the Funding Office, in Dollars and in immediately available funds. The Administrative Agent shall distribute such payments to the Lenders promptly upon receipt in like funds as received. If any payment hereunder (other than payments on the Eurodollar Loans) becomes due and payable on a day other than a Business Day, such payment shall be extended to the next succeeding Business Day. If any payment on a Eurodollar Loan becomes due and payable on a day other than a Business Day, the maturity thereof shall be extended to the next succeeding Business Day unless the result of such extension would be to extend such payment into another calendar month, in which event such payment shall be made on the immediately preceding Business Day. In the case of any extension of any payment of principal pursuant to the preceding two sentences, interest thereon shall be payable at the then applicable rate during such extension.

(d)Unless the Administrative Agent shall have been notified in writing by any Lender prior to a borrowing that such Lender will not make the amount that would constitute its share of such borrowing available to the Administrative Agent, the Administrative Agent may assume that such Lender is making such amount available to the Administrative Agent, and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower a corresponding amount. If such amount is not made available to the Administrative Agent by the required time on the Effective Date, such Lender shall pay to the Administrative Agent, on demand, such amount with interest thereon, at a rate equal to the greater of (i) the Federal Funds Effective Rate and (ii) a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation, for the period until such Lender makes such amount immediately available to the Administrative Agent. A certificate of the Administrative Agent submitted to any Lender with respect to any amounts owing under this paragraph shall be conclusive in the absence of manifest error. If such Lender’s share of such borrowing is not made available to the Administrative Agent by such Lender within three Business Days after the Effective Date, the Administrative Agent shall also be entitled to recover such amount with interest thereon at the rate per annum applicable to ABR Loans from the Borrower within 30 days after written demand therefor.

(e)Unless the Administrative Agent shall have been notified in writing by the Borrower prior to the date of any payment due to be made by the Borrower hereunder that the Borrower will not make such payment to the Administrative Agent, the Administrative Agent may assume that the Borrower is making such payment, and the Administrative Agent may, but shall not be required to, in reliance upon such assumption, make available to the Lenders their respective pro rata shares of a corresponding amount. If such payment is not made to the Administrative Agent by the Borrower within three Business Days after such due date, the Administrative Agent shall be entitled to recover, on demand, from each Lender to which any amount which was made available pursuant to the preceding sentence, such amount with interest thereon at the rate per annum equal to the daily average Federal Funds Effective Rate. Nothing herein shall be deemed to limit the rights of the Administrative Agent or any Lender against the Borrower.

(f)The Borrower agrees that, upon the request to the Administrative Agent by any Lender, the Borrower will promptly execute and deliver to such Lender a promissory note (a “Note”) of the Borrower evidencing any Loans (or any portion thereof) of such Lender, substantially in the form of Exhibit H, with appropriate insertions as to date and principal amount; provided, that delivery of Notes shall not be a condition precedent to the occurrence of the Effective Date or the making of the Loans on the Effective Date.

(g)If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.14(d), then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent hereunder for the account of such Lender for the benefit of the Administrative Agent to satisfy such Lender’s obligations to the Administrative Agent, as the case may be, under such Section until all such unsatisfied obligations are fully paid, and/or (ii) so long as such Lender is a Defaulting Lender, hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

1.3Change of Law.

(a)If a Change of Law shall:

Section 16.subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its Loans, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

Section 17.impose, modify or hold applicable any reserve, special deposit, compulsory loan, Federal Deposit Insurance Corporation insurance charge or other similar insurance charge or similar requirement against assets held by, deposits or other liabilities in or for the account of, advances, loans or other extensions of credit by, or any other acquisition of funds by, any Lender that is not otherwise included in the determination of the Eurodollar Rate, which requirements are generally applicable to advances, loans and other extensions of credit made by such Lender; or

Section 18.impose on any Lender any other condition that is generally applicable to loans made by such Lender or participations therein;

and the result of any of the foregoing is to increase the cost to such Lender or such other Recipient, by an amount that such Lender or such other Recipient deems to be material, of making, converting into, continuing or maintaining the Loans, or to reduce any amount receivable hereunder in respect thereof, then, in any such case, the Borrower shall promptly pay such Lender or such other Recipient, within ten Business Days after its demand, any additional amounts necessary to compensate such Lender or such other Recipient for such increased cost or reduced amount receivable. If any Lender or other Recipient becomes entitled to claim any additional amounts pursuant to this paragraph, it shall promptly notify the Borrower (with a copy to the Administrative Agent) of the event by reason of which it has become so entitled; provided, however, that no Lender or other Recipient shall be entitled to demand such compensation more than 90 days following (x) the last day of the Interest Period in respect of which such demand is made or (y) the repayment of the Loan in respect of which such demand is made. Notwithstanding any other provision herein, no Lender shall demand compensation pursuant to this Section 2.15 if it shall not at the time be the general policy or practice of such Lender to demand such compensation from similarly situated borrowers (to the extent that such Lender has the right to do so under its credit facilities with similarly situated borrowers).

(a)If any Lender shall have determined that a Change of Law regarding capital or liquidity requirements shall have the effect of reducing the rate of return on such Lender’s capital or the capital of any corporation controlling such Lender as a consequence of its obligations hereunder to a level below that which such Lender or such corporation could have achieved but for such Change of Law (taking into consideration such Lender’s or such corporation’s policies with respect to capital adequacy or liquidity) by an amount deemed by such Lender to be material, then from time to time, after submission by such Lender to the Borrower (with a copy to the Administrative Agent) of a written request therefor, the Borrower shall pay to such Lender such additional amount or amounts as will compensate such Lender or such corporation for such reduction.

(b)A certificate as to any additional amounts payable pursuant to this Section 2.15 submitted by any Lender or any other Recipient to the Borrower (with a copy to the Administrative Agent) shall constitute prima facie evidence of such costs or amounts. Notwithstanding anything to the contrary in this Section 2.15, the Borrower shall not be required to compensate a Lender or any other Recipient pursuant to this Section 2.15 for any amounts incurred more than six months prior to the date that such Lender or such other Recipient notifies the Borrower of such Lender’s or such other Recipient’s intention to claim compensation therefor; provided that, if the circumstances giving rise to such claim have a retroactive effect, then such six-month period shall be extended to include the period of such retroactive effect not to exceed twelve months. The obligations of the Borrower pursuant to this Section 2.15 shall survive for 90 days after the termination of this Agreement and the payment of the Loans and all other amounts then due and payable hereunder.

1.2Taxes.

(a)Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall be made without deduction or withholding for any Taxes, except as required by applicable laws. If any

applicable laws (as determined in the good faith discretion of the Borrower or Administrative Agent making the payment) require the deduction or withholding of any Tax from any such payment, then (A) the Borrower or Administrative Agent, as applicable shall withhold or make such deductions as are determined by the Borrower or the Administrative Agent to be required, (B) the Borrower or Administrative Agent, as applicable shall timely pay the full amount withheld or deducted to the relevant Governmental Authority in accordance with such laws, and (C) to the extent that the withholding or deduction is made on account of Indemnified Taxes, the sum payable by the Borrower shall be increased as necessary so that after any required withholding or the making of all required deductions (including deductions applicable to additional sums payable under this Section 2.16) the applicable Recipient receives an amount equal to the sum it would have received had no such withholding or deduction been made.

(b)Without limiting the provisions of subsection (a) above, the Borrower shall timely pay to the relevant Governmental Authority in accordance with applicable law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(c)(i) The Borrower shall, and does hereby, indemnify each Recipient, and shall make payment in respect thereof within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 2.16) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender or another Recipient (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender or another Recipient, shall be conclusive absent manifest error.

Section 19.Each Lender shall, and does hereby, severally indemnify, and shall make payment in respect thereof within 10 days after demand therefor, (x) the Administrative Agent against any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (y) the Administrative Agent against any Taxes attributable to such Lender’s failure to comply with the provisions of Section 10.6(c)(iii) relating to the maintenance of a Participant Register and (z) the Administrative Agent against any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender, as the case may be, under this Agreement or any other Loan Document against any amount due to the Administrative Agent under this clause (ii).

(a)Upon request by the Borrower or the Administrative Agent, as the case may be, after any payment of Taxes by the Borrower or by the

Administrative Agent to a Governmental Authority as provided in this Section 2.16, the Borrower shall deliver to the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(b)(i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Sections 2.16(e)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

Section 20.Without limiting the generality of the foregoing,

(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(I)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed copies of IRS Form W-8BEN or W-8BEN-E, as applicable, establishing an

exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN or W-8BEN-E, as applicable, establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(II)executed copies of IRS Form W-8ECI;

(III)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit G-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed copies of IRS Form W-8BEN or W-8BEN-E, as applicable; or

(IV)to the extent a Foreign Lender is not the beneficial owner, executed copies of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN or W-8BEN-E, as applicable, a U.S. Tax Compliance Certificate substantially in the form of Exhibit G-2 or Exhibit G-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit G-4 on behalf of each such direct and indirect partner.

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be

prescribed by applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

(D)if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3) (C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the Effective Date.

Section 21.Each Lender agrees that if any form or certification it previously delivered pursuant to this Section 2.16 expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(a)At no time shall the Administrative Agent have any obligation to file for or otherwise pursue on behalf of a Lender, any refund of Taxes withheld or deducted from funds paid for the account of such Lender, as the case may be. If any Recipient determines, in its sole discretion exercised in good faith, that it has received a refund of, or credit with respect to, any Taxes as to which it has been indemnified pursuant to this Section 2.16 (including by the payment of additional amounts pursuant to this Section 2.16), it shall pay to the Borrower an amount equal to such refund or credit (but only to the extent of indemnity payments made under this Section 2.16 with respect to the Taxes giving rise to such refund or credit), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund or credit). The Borrower, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this paragraph (f) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event such indemnified party is required to repay such refund or credit to such Governmental Authority. Notwithstanding anything to the contrary in this paragraph (f), in no event will the indemnified party be required to pay any amount to the Borrower pursuant to this paragraph (f) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund or credit had not been deducted, withheld or otherwise imposed and the

indemnification payments or additional amounts with respect to such Tax had never been paid. This paragraph (f) shall not be construed to require any Recipient to make available its tax returns (or any other information relating to its Taxes that it deems confidential) to the Borrower or any other Person.

(b)Each party’s obligations under this Section 2.16 shall survive for one year after the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

1.2Indemnity. The Borrower agrees to indemnify each Lender for, and to hold each Lender harmless from, any loss (other than the loss of Applicable Margin) or expense that such Lender may sustain or incur as a consequence of (a) default by the Borrower in making a borrowing of, conversion into or continuation of Eurodollar Loans after the Borrower has given a notice requesting the same in accordance with the provisions of this Agreement, (b) default by the Borrower in making any prepayment of or conversion from Eurodollar Loans after the Borrower has given a notice thereof in accordance with the provisions of this Agreement or (c) the making of a prepayment of Eurodollar Loans on a day that is not the last day of an Interest Period with respect thereto. A certificate as to any amounts payable pursuant to this Section submitted to the Borrower by any Lender shall be conclusive in the absence of manifest error. This covenant shall survive for 90 days after the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

1.3Change of Lending Office. Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.15 or 2.16 with respect to such Lender, it will, if requested by the Borrower, use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event with the object of avoiding the consequences of such event; provided, that such designation is made on terms that, in the sole but reasonable judgment of such Lender, cause such Lender and its lending office(s) to suffer no unreimbursed economic disadvantage or any legal or regulatory disadvantage, and provided, further, that nothing in this Section shall affect or postpone any of the obligations of the Borrower or the rights of any Lender pursuant to Section 2.15 or 2.16.

1.4Replacement of Lenders. The Borrower shall be permitted to replace any Lender that (a) requests (on its behalf or any of its Participants) reimbursement for amounts owing pursuant to Section 2.15 or 2.16, (b) provides notice under Section 2.21 or (c) becomes a Defaulting Lender, with a replacement financial institution; provided that (i) such replacement does not conflict with any Requirement of Law, (ii) no Event of Default shall have occurred and be continuing at the time of such replacement, (iii) prior to any such replacement, such Lender shall have taken no action under Section 2.18 which eliminates the continued need for payment of amounts owing pursuant to Section 2.15 or 2.16, (iv) the replacement financial institution shall purchase, at par, all Loans and other amounts owing to such replaced Lender on or prior to the date of replacement, (v) the Borrower shall be liable to such replaced Lender under Section 2.17 if any Eurodollar Loan owing to such replaced Lender shall be purchased other than on the last day of the Interest Period relating thereto, (vi) the replacement financial institution, if not already a Lender, shall be reasonably satisfactory to the Administrative Agent, (vii) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 10.6 (provided that the Borrower shall be obligated to pay the registration and processing fee referred to

therein), (viii) until such time as such replacement shall be consummated, the Borrower shall pay all additional amounts (if any) required pursuant to Section 2.15 or 2.16, as the case may be, and (ix) any such replacement shall not be deemed to be a waiver of any rights that the Borrower, the Administrative Agent or any other Lender shall have against the replaced Lender.

1.5Defaulting Lenders. Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as that Lender is no longer a Defaulting Lender, to the extent permitted by applicable law:

(a)any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Section 7 or otherwise, and including any amounts made available to the Administrative Agent by that Defaulting Lender pursuant to Section 9.7), shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third, if so determined by the Borrower with the consent of the Administrative Agent, not to be unreasonably withheld, to be held in a non-interest bearing deposit account and released in order to satisfy obligations of that Defaulting Lender to fund Loans under this Agreement; fourth, to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; fifth, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; and sixth, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if such payment is a payment of the principal amount of the Loans in respect of which that Defaulting Lender has not fully funded its appropriate share such payment shall be applied solely to pay the Loans of all non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Loans of that Defaulting Lender. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 2.20(a) shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto;

(b)[Reserved];

(c)[Reserved];

(d)[Reserved]; and

(e)that Defaulting Lender’s right to approve or disapprove any amendment, supplement, modification, waiver or consent with respect to this

Agreement shall be restricted as set forth in the definition of “Required Lenders” and Section 10.1.

If the Borrower and the Administrative Agent reasonably determine in writing that a Defaulting Lender should no longer be deemed to be a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein (which may include arrangements with respect to any cash collateral), that Lender will, to the extent applicable, purchase that portion of outstanding Loans of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Loans to be held on a pro rata basis by the Lenders in accordance with their Percentages, whereupon that Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.

1.6Illegality. If any Lender determines that any Law has made it unlawful, or that any Governmental Authority has asserted that it is unlawful, for any Lender or its applicable lending office to make, maintain, or fund Loans whose interest is determined by reference to the Eurodollar Rate, or to determine or charge interest rates based upon the Eurodollar Rate, or any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, then, upon notice thereof by such Lender to the Borrower (through the Administrative Agent), (a) any obligation of such Lender to make or continue Eurodollar Loans or to convert ABR Loans to Eurodollar Loans shall be suspended, and (b) if such notice asserts the illegality of such Lender making or maintaining ABR Loans the interest rate on which is determined by reference to the Eurodollar Rate component of the ABR, the interest rate on which ABR Loans of such Lender shall, if necessary to avoid such illegality, be determined by the Administrative Agent without reference to the Eurodollar Rate component of the ABR, in each case until such Lender notifies the Administrative Agent and the Borrower that the circumstances giving rise to such determination no longer exist. Upon receipt of such notice, (i) the Borrower shall, upon demand from such Lender (with a copy to the Administrative Agent), prepay or, if applicable, convert all Eurodollar Loans of such Lender to ABR Loans (the interest rate on which ABR Loans of such Lender shall, if necessary to avoid such illegality, be determined by the Administrative Agent without reference to the Eurodollar Rate component of the ABR), either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Loans to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Loans and (ii) if such notice asserts the illegality of such Lender determining or charging interest rates based upon the Eurodollar Rate, the Administrative Agent shall during the period of such suspension compute the ABR applicable to such Lender without reference to the Eurodollar Rate component thereof until the Administrative Agent is advised in writing by such Lender that it is no longer illegal for such Lender to determine or charge interest rates based upon the Eurodollar Rate. Upon any such prepayment or conversion, the Borrower shall also pay accrued interest on the amount so prepaid or converted, together with any additional amounts required pursuant to Section 2.17.

Section 22.[RESERVED].

Section 23.REPRESENTATIONS AND WARRANTIES

To induce the Administrative Agent and the Lenders to enter into this Agreement and to make the Loans, the Borrower hereby represents and warrants to the Administrative Agent and each Lender, on the Effective Date, that:

1.1Financial Condition. (a) The audited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as of December 31, 2020, and the related consolidated statements of income and cash flows for the fiscal year ended on such date, reported on by Deloitte & Touche LLP, and (b) the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as of March 31, 2021, and the related consolidated statements of income and cash flows for the portion of the fiscal year ended on such date, each delivered to the Administrative Agent prior to the Amendment No. 1 Effective Date, in each case, (i) were prepared in accordance with GAAP consistently applied throughout the periods covered thereby, except as otherwise expressly noted therein, and (ii) present fairly in all material respects the consolidated financial condition of the Borrower and its consolidated Subsidiaries as of such date, and its consolidated income and its consolidated cash flows for the respective fiscal year or portion of the fiscal year then ended, subject, in the case of the financial statements referred to in clause (b), to the absence of footnotes and to normal year-end audit adjustments.

1.2No Change. Since December 31, 2020, no Specified Material Adverse Effect has occurred.

1.3Existence; Compliance with Law. Each of the Borrower and its Significant Subsidiaries (a) is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization, (b) has the organizational power and organizational authority to own and operate its property, to lease the property it operates as lessee and to conduct the business in which it is currently engaged, (c) is duly qualified as a foreign corporation or other organization and in good standing under the laws of each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification except to the extent that the failure to so qualify could not reasonably be expected to have a Material Adverse Effect and (d) is in compliance with all Requirements of Law except for any Requirements of Law being contested in good faith by appropriate proceedings and except to the extent that the failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

1.4Power; Authorization; Enforceable Obligations. The Borrower has the corporate power and corporate authority to execute and deliver and to perform its obligations under the Loan Documents and to obtain extensions of credit hereunder. The Borrower has taken all necessary corporate action to authorize the execution and delivery of, and performance of its obligations under, the Loan Documents to which it is a party and to authorize the extensions of credit on the terms and conditions of this Agreement. No consent or authorization of, filing with, notice to or other act by or in respect of, any Governmental Authority or any other Person is required in connection with the extensions of credit hereunder or with the execution, delivery, performance, validity or enforceability of this Agreement or any of the Loan Documents, except (i) consents,

authorizations, filings and notices which have been obtained or made and are in full force and effect, (ii) any consent, authorization or filing that may be required in the future the failure of which to make or obtain could not reasonably be expected to have a Material Adverse Effect and (iii) applicable Requirements of Law (including the approval of the CPUC) prior to foreclosure or other exercise of remedies under the Loan Documents. This Agreement has been, and each other Loan Document upon execution and delivery will be, duly executed and delivered. This Agreement constitutes, and each other Loan Document upon execution will constitute, a legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, except as enforceability may be limited by (x) applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally, laws of general application related to the enforceability of securities secured by real estate and by general equitable principles (whether enforcement is sought by proceedings in equity or at law) and (y) applicable Requirements of Law (including the approval of the CPUC) prior to foreclosure or other exercise of remedies hereunder or under the Loan Documents.

1.5No Legal Bar. The execution and delivery of, and the performance of the obligations under, this Agreement and the other Loan Documents, the borrowing of the Loans hereunder and the use of the proceeds thereof will not violate in any material respect any Requirement of Law or any Contractual Obligation of the Borrower or any of its Significant Subsidiaries and will not result in, or require, the creation or imposition of any Lien on any of their respective properties or revenues pursuant to any Requirement of Law or any such Contractual Obligation (other than the Liens created by the Loan Documents and the FMB Indenture).

1.6Litigation. (a) No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened in writing by or against the Borrower or any of its Significant Subsidiaries or against any of their respective material properties or revenues with respect to any of the Loan Documents.

(b)No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened in writing by or against the Borrower or any of its Significant Subsidiaries or against any of their respective material properties or revenues, except as disclosed in the Specified Exchange Act Filings, that could reasonably be expected to have a Material Adverse Effect.

1.7No Default. No Default or Event of Default has occurred and is continuing.

1.8Taxes. The Borrower and each of its Significant Subsidiaries has filed or caused to be filed all Federal and state returns of income and franchise taxes imposed in lieu of net income taxes and all other material tax returns that are required to be filed and has paid all taxes shown to be due and payable on said returns or with respect to any claims or assessments for taxes made against it or any of its property by any Governmental Authority (other than (i) any amounts the validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable, and (ii) claims which could not reasonably be expected to have a

Material Adverse Effect). No material tax Liens have been filed against the Borrower or any of its Significant Subsidiaries other than (A) Liens for taxes which are not delinquent or (B) Liens for taxes which are being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable.

1.9Federal Regulations. No part of the proceeds of any Loans hereunder, will be used for “buying” or “carrying” any “margin stock” within the respective meanings of each of the quoted terms under Regulation U as now and from time to time hereafter in effect or for any purpose that violates the provisions of the Regulations of the Federal Reserve Board.

1.10ERISA. No Reportable Event has occurred during the five year period prior to the date on which this representation is made or deemed made with respect to any Plan, and each Plan has complied with the applicable provisions of ERISA and the Code, except, in each case, to the extent that any such Reportable Event or failure to comply with the applicable provisions of ERISA or the Code could not reasonably be expected to result in a Material Adverse Effect. During the five year period prior to the date on which this representation is made or deemed made, there has been no (i) failure to make a required contribution to any Plan that would result in the imposition of a Lien or other encumbrance or the provision of security under Section 430 of the Code or Section 303 or 4068 of ERISA, or the arising of such a Lien or encumbrance; or (ii) “unpaid minimum required contribution” or “accumulated funding deficiency” (as defined or otherwise set forth in Section 4971 of the Code or Part 3 of Subtitle B of Title I of ERISA), whether or not waived, except, in each case, to the extent that such event could not reasonably be expected to result in a Material Adverse Effect. No termination of a Single Employer Plan has occurred, and no Lien in favor of the PBGC or a Plan has arisen, during such five-year period. The present value of all accrued benefits under each Single Employer Plan (based on those assumptions used to fund such Plan) did not, as of the last annual valuation date for which a certified actuarial valuation report is available prior to the date on which this representation is made or deemed made, exceed the value of the assets of such Plan allocable to such accrued benefits, except as could not reasonably be expected to result in a Material Adverse Effect. Neither the Borrower nor any Commonly Controlled Entity has had a complete or partial withdrawal from any Multiemployer Plan during the five year period prior to the date on which this representation is made or deemed made that has resulted or could reasonably be expected to result in a material liability under ERISA, and neither the Borrower nor any Commonly Controlled Entity would become subject to any liability under ERISA if the Borrower or any such Commonly Controlled Entity were to withdraw completely from all Multiemployer Plans as of the valuation date most closely preceding the date on which this representation is made or deemed made, except as could not reasonably be expected to result in a Material Adverse Effect. No such Multiemployer Plan is in endangered or critical status (within the meaning of Section 305 of ERISA) or in Insolvency.

1.11Investment Company Act; Other Regulations. The Borrower is not an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended. On the Effective Date, the Borrower is not subject to regulation under any Requirement of Law (other than (a) Regulation X of the Federal Reserve Board and (b) Sections 817-830, and Sections 701 and 851 of the California

Public Utilities Code) that limits its ability to incur Indebtedness under this Agreement.

1.12Use of Proceeds. The proceeds of the Loans shall be used to fund the transactions contemplated under the Plan of Reorganization.

1.13Environmental Matters. Except as disclosed in the Specified Exchange Act Filings, the Borrower and its Significant Subsidiaries are not subject to any pending violations or liabilities under Environmental Laws or relating to the disposal, spill or other release of Materials of Environmental Concern that would reasonably be expected to have a Material Adverse Effect, and, to the knowledge of the Borrower, there are no facts, circumstances or conditions that could reasonably be expected to give rise to such violations or liabilities.

1.14Regulatory Matters. Solely by virtue of the execution, delivery and performance of, or the consummation of the transactions contemplated by this Agreement, no Lender shall be or become subject to regulation (a) under the FPA or (b) as a “public utility” or “public service corporation” or the equivalent under any Requirement of Law.

1.15Sanctions; Anti-Corruption. None of the Borrower, any of its Subsidiaries, nor, to the knowledge of the Borrower, any director, officer, agent, Affiliate or employee of the Borrower or any of its Subsidiaries is currently (i) the subject of any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department or the U.S. State Department (“Sanctions”) or (ii) located, organized or resident in a country or territory that is, or whose government is, the subject of any Sanctions. None of the Borrower, any of its Subsidiaries nor, to the knowledge of the Borrower, any director, officer, agent, Affiliate or employee of the Borrower or any of its Subsidiaries, has taken any action, directly or indirectly, that would result in a violation in any material respect by any such Person of the United States Foreign Corrupt Practices Act of 1977, as amended (“FCPA”) or of any other anti-bribery or anti-corruption laws, rules, regulations legally applicable to such Persons (collectively, “Anti-Corruption Laws”). The Borrower will not use the proceeds of the Loans, or lend, contribute or otherwise make available such proceeds (a) to any Subsidiary, Affiliate, joint venture partner or other Person or entity, to fund the activities of any Person, or in any country or territory, that, at the time of such funding, is, or whose government is, the subject of any Sanctions, or (a) directly, or, to the knowledge of the Borrower, indirectly, for any payments to any governmental official or employee, political party, official of a political party, candidate for political office, or anyone else acting in an official capacity, in order to obtain, retain or direct business or obtain any improper advantage, in violation of the FCPA or of any Anti-Corruption Laws.

1.16Affected Financial Institutions. The Borrower is not an Affected Financial Institution.

1.17Solvency. The Borrower and its Subsidiaries, on a consolidated basis, are Solvent as of the Amendment No. 1 Effective Date.

1.18Disclosure.

(a)All written information relating to the Borrower, its Subsidiaries and their respective businesses, other than any projections, estimates and other forward-looking materials and information of a general economic or industry specific nature, that has been provided by or on behalf of the Borrower to the Administrative Agent or the Lenders in connection with the transactions contemplated hereby does not, when taken as a whole, contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements contained therein not materially misleading in light of the circumstances under which such statements were made (giving effect to all supplements and updates thereto). Any projected information, estimates, other forward-looking materials and pro forma financial information that have been made available to any Lenders or the Administrative Agent prior to the Effective Date in connection with the transactions contemplated hereby have been prepared in good faith based upon assumptions believed by the Borrower to be reasonable as of the date such information was furnished to the Lenders and as of the Effective Date (it being understood that actual results may vary materially from such projections and pro forma information and such projections and pro forma information are not a guarantee of performance).

(b)As of the Effective Date, to the knowledge of the Borrower, the information included in any Beneficial Ownership Certification provided on or prior to the Effective Date to any Lender in connection with this Agreement is true and correct in all respects.

1.19Status of Obligations. The issuance to the Administrative Agent of the Senior Bonds provides the Lenders, as beneficial holders of the Senior Bonds through the Administrative Agent, the benefit of the Lien of the FMB Indenture equally and ratably with the holders of other First Mortgage Bonds.

1.20Ownership of Property. As of the Effective Date, each of the Borrower and its Significant Subsidiaries has good title to, or valid leasehold interests in, all its real and personal property material to its business, subject to no Liens other than Liens permitted under Section 7.3, except for where the failure would not, individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

1.21Covered Entity. The Borrower is not a Covered Entity.

Section 24.CONDITIONS PRECEDENT

1.1Conditions to the Effective Date. The occurrence of the Effective Date and the obligation of each Lender to make its Loans hereunder on the Effective Date is subject to the satisfaction of the following conditions precedent:

(a)Credit Agreement. The Administrative Agent shall have received this Agreement (including copies of all schedules attached hereto in a form reasonably satisfactory to the Lenders), executed and delivered by the Administrative Agent, the Borrower and each Person listed on Schedule 1.1.

(b)Consents and Approvals. All governmental and third party consents and approvals necessary in connection with the execution and delivery of this Agreement and the other Loan Documents and the consummation of the transactions contemplated hereby shall have been

obtained and be in full force and effect; and the Administrative Agent shall have received a certificate of a Responsible Officer to the foregoing effect.

(c)KYC Information. At least three (3) Business Days prior to the Effective Date, the Administrative Agent and each Lender shall have received all documentation and information relating to the Borrower as is reasonably requested in writing by the Administrative Agent and/or any such Lender at least ten (10) Business Days prior to the Effective Date that is required by Governmental Authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation. If the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation and the Administrative Agent or any Lender so request at least five (5) Business Days prior to the Effective Date, then at least three (3) Business Days prior to the Effective Date, the Borrower shall have delivered to the Administrative Agent and/or any such Lender a Beneficial Ownership Certification in relation to the Borrower.

(d)Bond Documents. The Administrative Agent shall have received:

Section 25.the Bond Delivery Agreement, duly executed and delivered by the Borrower and Administrative Agent;

Section 26.the Senior Bonds in a face amount equal to the Loans as of the Effective Date, duly issued and authenticated under the FMB Indenture and in a form reasonably satisfactory to the Administrative Agent;

Section 27.the Supplemental Indenture, duly executed and delivered by the Borrower and the Indenture Trustee and in a form reasonably satisfactory to the Administrative Agent;

Section 28.a certificate of a duly authorized officer of the Indenture Trustee certifying that each Senior Bond has been authenticated and is outstanding under the FMB Indenture;

Section 29.copies of all legal opinions and other documents delivered to the Indenture Trustee by or on behalf of the Borrower on or prior to the Effective Date in connection with the issuance of each Senior Bond; and

Section 30.copies of all title reports and commitments as of the Effective Date with respect to the Mortgaged Property consisting of real property as to which Liens in favor of the Indenture Trustee, for the benefit of the holders of the First Mortgage Bond, has been granted.

(a)Fees. The Lenders, the Arrangers and the Administrative Agent shall have received all fees required to be paid, and all expenses for which invoices have been presented (including the reasonable fees and expenses of legal counsel) on or before the date that is two (2) Business Days prior to the Effective Date.

(b)Closing Certificate; Certified Articles of Incorporation; Good Standing Certificates. The Administrative Agent shall have received (i) a certificate of the Borrower, dated the Effective Date, substantially in the form of Exhibit D, with appropriate insertions and attachments, including the articles of incorporation of the Borrower certified as of a recent date by the Secretary

of State of the State of California, (ii) a good standing certificate for the Borrower dated as of a recent date from the Secretary of State of the State of California, and (iii) a certificate of a Responsible Officer, dated the Effective Date, confirming the satisfaction of the conditions precedent set forth in Sections 5.1(h) and (i).

(c)Legal Opinion. The Administrative Agent shall have received the legal opinion of (i) Hunton Andrews Kurth LLP, counsel to the Borrower, and (ii) Munger, Tolles & Olson LLP, special California regulatory counsel to the Borrower, each in a form reasonably satisfactory to the Administrative Agent.

(d)Representations and Warranties. Each of the representations and warranties made by the Borrower in this Agreement that does not contain a materiality qualification shall be true and correct in all material respects on and as of the Effective Date, and each of the representations and warranties made by the Borrower in this Agreement that contains a materiality qualification shall be true and correct on and as of the Effective Date (or, in each case, to the extent such representations and warranties specifically relate to an earlier date, that such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date).

(e)No Default. No Default or Event of Default shall have occurred and be continuing on the Effective Date or would result from the funding of the Loans on the Effective Date.

(f)Notice of Borrowing. The Administrative Agent shall have received a notice of borrowing in accordance with the requirements of Section 2.2.

(g)Solvency. The Administrative Agent shall have received a solvency certificate from the chief financial officer of the Borrower in substantially the form of Exhibit I hereto.

Section 31.AFFIRMATIVE COVENANTS

The Borrower hereby agrees that, so long as any Loan, any interest on any Loan or any fee payable to any Lender or the Administrative Agent hereunder remains outstanding, or any other amount then due and payable is owing to any Lender or the Administrative Agent hereunder, the Borrower shall and, with respect to Sections 6.3 and 6.6(b), shall cause its Significant Subsidiaries to:

1.1Financial Statements. Furnish to the Administrative Agent with a copy for each Lender, and the Administrative Agent shall deliver to each Lender:

(a)as soon as available, but in any event within 120 days after the end of each fiscal year of the Borrower, a copy of the audited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such year and the related audited consolidated statements of income and cash flows for such year, setting forth in each case in comparative form the figures for the previous year, reported on without a “going concern” or like qualification or exception, or qualification arising out of the scope of the audit, by Deloitte & Touche LLP or other independent certified public accountants of nationally recognized standing; and

(b)as soon as available, but in any event not later than 60 days after the end of each of the first three quarterly periods of each fiscal year of the Borrower, the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such quarter and the related unaudited consolidated statements of income and cash flows for such quarter and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year, certified by a Responsible Officer as being fairly stated in all material respects (subject to the absence of footnotes and normal year-end audit adjustments).

All such financial statements shall (x) be complete and correct in all material respects and (y) shall be prepared in reasonable detail and in accordance with GAAP applied (except as approved by such accountants or officer, as the case may be, and disclosed in reasonable detail therein) consistently throughout the periods reflected therein and with prior periods, subject, in each case to the absence of footnotes and to normal year-end audit adjustments. The Borrower shall be deemed to have delivered the financial statements required to be delivered pursuant to this Section 6.1 upon the filing of such financial statements by the Borrower through the SEC’s EDGAR system (or any successor electronic gathering system that is publicly available free of charge) or the publication by the Borrower of such financial statements on its website.

1.2Certificates; Other Information. Furnish to the Administrative Agent, for delivery to the Lenders:

(a)within two Business Days after the delivery of any financial statements pursuant to Section 6.1, (i) a certificate of a Responsible Officer stating that such Responsible Officer has obtained no actual knowledge of any Default or Event of Default except as specified in such certificate and (ii) a Compliance Certificate, substantially in the form of Exhibit C, containing all information and calculations reasonably necessary for determining compliance by the Borrower with the provisions of this Agreement referred to therein as of the last day of the fiscal quarter or fiscal year of the Borrower, as the case may be;

(b)within five days after the same are sent, copies of all financial statements and reports that the Borrower sends to the holders of any class of its debt securities or public equity securities, provided that, such financial statements and reports shall be deemed to have been delivered upon the filing of such financial statements and reports by the Borrower through the SEC’s EDGAR system (or any successor electronic gathering system that is publicly available free of charge) or publication by the Borrower of such financial statements and reports on its website;

(c)promptly, such additional financial and other information (other than any such information the disclosure of which is prohibited by applicable law or binding agreement or subject to attorney-client privilege or constitutes attorney-work product or constitutes non-financial trade secrets or non-financial proprietary information so long as (x) such confidentiality obligation was not entered into in contemplation hereof and (y) the Borrower provides such Lender with notice that information is being withheld due to the existence of such confidentiality obligation) as any Lender, through the Administrative Agent, may from time to time reasonably request; and

(d)promptly, such documentation and other information that the Administrative Agent or such Lender reasonably requests in order to comply with its ongoing obligations under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation.

1.3Payment of Taxes. Pay all taxes due and payable or any other tax assessments made against the Borrower or any of its Significant Subsidiaries or any of their respective property by any Governmental Authority (other than (i) any amounts the validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable or (ii) where the failure to effect such payment could not reasonably be expected to have a Material Adverse Effect).

1.4Maintenance of Existence; Compliance. (a)(i) Preserve, renew and keep in full force and effect its organizational existence and (ii) take all reasonable action to maintain all rights, privileges and franchises necessary or desirable in the normal conduct of its business, except, in each case, as otherwise permitted by Section 7.4 and except, in the case of clause (ii) above, to the extent that failure to do so could not reasonably be expected to have a Material Adverse Effect; (b) comply with all Contractual Obligations except to the extent that failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect and (c) comply with all Requirements of Law except for any Requirements of Law being contested in good faith by appropriate proceedings or except to the extent that failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

1.5Maintenance of Property; Insurance. (a) Keep all property useful and necessary in its business in good working order and condition, ordinary wear and tear and casualty excepted, except to the extent that failure to do so could not, in the aggregate, reasonably be expected to have a Material Adverse Effect, and (b) maintain with financially sound and reputable insurance companies insurance on all its material property in at least such amounts and against at least such risks as are usually insured against in the same general area by companies engaged in the same or a similar business of comparable size and financial strength and owning similar properties in the same general areas in which the Borrower operates, which may include self-insurance, if determined by the Borrower to be reasonably prudent.

1.6Inspection of Property; Books and Records; Discussions. (a) Keep proper books of records and account in which full, true and correct entries in conformity with GAAP and all Requirements of Law shall be made of all dealings and transactions in relation to its business and activities and (b) unless a Default or Event of Default has occurred and is continuing, not more than once a year and after at least five Business Days’ notice, (i) permit representatives of any Lender to visit and inspect any of its properties and examine and make abstracts from any of its books and records at any reasonable time to discuss the business, operations, properties and financial and other condition of the Borrower and its Significant Subsidiaries with officers and employees of the Borrower and its Significant Subsidiaries and (ii) use commercially reasonable efforts to provide for the Lenders (in the presence of representatives of the Borrower) to meet with the independent certified public accountants of the Borrower and its Significant Subsidiaries; provided, that any such visits or inspections shall be subject to such

conditions as the Borrower and each of its Significant Subsidiaries shall deem necessary based on reasonable considerations of safety, security and confidentiality; and provided, further, that neither the Borrower nor any Significant Subsidiary shall be required to disclose to any Person any information the disclosure of which is prohibited by applicable law or binding agreement or subject to attorney-client privilege or constitutes attorney-work product or constitutes non-financial trade secrets or non-financial proprietary information so long as (x) such confidentiality obligation was not entered into in contemplation hereof and (y) the Borrower provides such Lender with notice that information is being withheld due to the existence of such confidentiality obligation.

1.7Notices. Give notice to the Administrative Agent, and the Administrative Agent shall deliver such notice to each Lender, promptly upon any Responsible Officer obtaining knowledge of:

(a)the occurrence of any Default or Event of Default;

(b)any change in the Rating issued by either S&P or Moody’s; and

(c)the occurrence of an ERISA Event which, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect (provided, that, any judicial proceeding instituted by PBGC that, within 60 days after the institution of such proceeding, has been withdrawn or stayed by PBGC or otherwise, shall be disregarded for the purpose of this Section 6.7(c)).

1.8Maintenance of Licenses, etc. Maintain in full force and effect any authorization, consent, license or approval of any Governmental Authority necessary for the conduct of the Borrower’s business as now conducted by it or necessary in connection with this Agreement, except to the extent the failure to do so could not reasonably be expected to have a Material Adverse Effect.

1.9Further Assurances.

(a)(i) Comply with Section 7.08(a) of the FMB Indenture, (ii) deliver to the Administrative Agent within 120 days after the Effective Date, a copy of the Opinion of Counsel (as defined in the FMB Indenture) delivered to the Indenture Trustee under Section 7.08(a)(i) of the FMB Indenture relating the Supplemental Indenture and (iii) deliver to the Administrative Agent a copy of each Opinion of Counsel delivered to the Indenture Trustee under Section 7.08(a)(ii) of the FMB Indenture relating to the Supplemental Indenture.

(b)Promptly upon the reasonable request by the Administrative Agent, or by the Required Lenders through the Administrative Agent, (i) correct any material defect or error that may be discovered in any Loan Document or the execution, acknowledgment, filing or recordation thereof and (ii) do, execute, acknowledge and deliver any and all such further certificates, documents, agreements and other instruments as reasonably required from time to time to carry out more effectively the purposes of the Loan Documents.

1.10Use of Proceeds. The Borrower shall use the proceeds of the Loans in accordance with Section 4.12.

Section 32.NEGATIVE COVENANTS

The Borrower hereby agrees that, so long as any Loan, or any interest on any Loan or any fee payable to any Lender or the Administrative Agent hereunder remains outstanding, or any other amount then due and payable is owing to any Lender or the Administrative Agent hereunder, the Borrower shall not and shall not permit its Significant Subsidiaries to:

1.1Indebtedness. At all times prior to the Indebtedness Covenant Release Date, create, incur, assume or permit to exist any Indebtedness, except for:

(a)Indebtedness and other Obligations created hereunder;

(b)Indebtedness of the Borrower under the Utility Revolving Credit Agreement in an aggregate outstanding principal amount not to exceed $3,500,000,000 plus any additional amounts permitted to be incurred thereunder pursuant to Section 2.3 of the Utility Revolving Credit Agreement as in effect on the date hereof and any Permitted Refinancing thereof;

(c)Indebtedness of the Borrower outstanding on the Effective Date in an aggregate outstanding principal amount not to exceed, together with any Loans outstanding hereunder on the Effective Date, $33,350,000,000 and any Permitted Refinancing thereof;

(d)Indebtedness (i) pursuant to tenders, statutory obligations, bids, leases, governmental contracts, trade contracts, surety, stay, customs, appeal, performance and/or return of money bonds or other similar obligations incurred in the ordinary course of business and (ii) in respect of letters of credit, bank guaranties, surety bonds, performance bonds or similar instruments and reimbursement obligations to support any of the foregoing items;

(e)(i) Guarantee Obligations with respect to the obligations of suppliers, customers and licensees and other third parties in the ordinary course of business, (ii) Indebtedness incurred in the ordinary course of business to pay the deferred purchase price of goods or services or progress payments in connection with such goods and services and (iii) Indebtedness in respect of letters of credit, bankers’ acceptances, bank guaranties or similar instruments supporting trade payables, warehouse receipts or similar facilities entered into in the ordinary course of business, workers compensation claims or other employee benefits;

(f)Guarantee Obligations with respect to Indebtedness otherwise permitted to be incurred pursuant to this Section 7.1 and Guarantee Obligations with respect to the obligations of Subsidiaries and joint ventures of the Borrower; provided that no such Guarantee Obligations with respect to Indebtedness of the Borrower constituting debt for borrowed money or evidenced by notes, bonds, debentures or other similar instruments (including, for the avoidance of doubt, the First Mortgage Bonds) shall be permitted except to the extent provided by a Person that is, or concurrently with providing such Guarantee Obligations becomes, a guarantor of the Obligations hereunder on terms and pursuant to documentation reasonably satisfactory to the Administrative Agent;

(g)Indebtedness consisting of (i) the financing of insurance premiums and/or (ii) take-or-pay obligations contained in supply arrangements;

(h)Indebtedness with respect to Capital Lease Obligations and purchase money Indebtedness; provided, that the aggregate outstanding principal amount of Indebtedness with respect to Capital Lease Obligations shall not exceed $500,000,000 at any one time;

(i)(i) obligations under any Cash Management Agreement and (ii) Indebtedness under any Swap Agreement permitted under Section 7.6;

(j)Indebtedness arising from any agreement providing for indemnification, adjustment or purchase price or similar obligations (including contingent earn-out obligations) incurred in connection with any Disposition or any purchase of assets or Capital Stock, and Indebtedness arising from guaranties, letters of credit, bank guaranties, surety bonds, performance bonds or similar instruments securing the performance of the Borrower or its Subsidiaries pursuant to any such agreement;

(k)Indebtedness in respect of banking services and incentive, supplier finance or similar programs incurred in the ordinary course of business;

(l)customer deposits and advance payments received in the ordinary course of business from customers for goods and services purchased in the ordinary course of business;

(m)Indebtedness representing deferred compensation to employees, consultants or independent contractors incurred in the ordinary course of business;

(n)Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or other similar instrument drawn against insufficient funds in the ordinary course of business;

(o)endorsements for collection or deposit in the ordinary course of business;

(p)Indebtedness issued or incurred to fund rate base growth in an aggregate outstanding principal amount not to exceed $9,000,000,000 at any time and any Permitted Refinancing thereof; and

(q)other Indebtedness of the Borrower in an aggregate outstanding principal amount not to exceed the excess, if any, of 10% of Net Tangible Assets of the Borrower over the amount of Indebtedness incurred pursuant to clause (p) above.

Notwithstanding anything herein to the contrary, no Guarantee Obligations from any Significant Subsidiary of the Borrower with respect to Indebtedness of the Borrower constituting debt for borrowed money or evidenced by notes, bonds, debentures or other similar instruments (including, for the avoidance of doubt, the First Mortgage Bonds) shall be permitted hereunder except to the extent provided by a Person that is, or concurrently with providing such Guarantee Obligations becomes, a guarantor of the Obligations hereunder on terms and pursuant to documentation reasonably satisfactory to the Administrative Agent.

1.2Consolidated Capitalization Ratio. Permit the Consolidated Capitalization Ratio on the last day of any fiscal quarter, from and after the last day of the first fiscal quarter ending after the Effective Date, to exceed 0.65 to 1.00.

1.3Liens. Create, incur, assume or suffer to exist any Lien upon any assets of the Borrower or any Significant Subsidiary, whether now owned or hereafter acquired, except for (a) Liens securing the Obligations under this Agreement and the other Loan Documents and (b) Liens permitted under Section 7.06(b) of the FMB Indenture.

1.4Fundamental Changes. Enter into any merger, consolidation or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or Dispose of all or substantially all of its property or business (including, without limitation, rental equipment or leasehold interests and excluding the sale or transfer of any accounts receivable or of any amounts that are accrued and recorded in a regulatory account for collections by the Borrower, in each case, in connection with a securitization transaction including, without limitation, any A/R Securitization Transaction), except that the Borrower may be merged, consolidated or amalgamated with another Person or Dispose of all or substantially all of its property or business so long as, after giving effect to such transaction, (a) no Default or Event of Default shall have occurred and be continuing, (b) either (i) the Borrower is the continuing or surviving corporation of such merger, consolidation or amalgamation or (ii) the continuing or surviving corporation of such merger, consolidation or amalgamation, if not the Borrower or the purchaser, (x) shall be an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia, (y) shall have assumed all obligations of the Borrower under the Loan Documents pursuant to arrangements reasonably satisfactory to the Administrative Agent and (z) to the extent requested by the Administrative Agent or any Lender, shall have promptly provided to the Administrative Agent or such Lender all documentation and other information that may be required by the Administrative Agent or such Lender in order to enable compliance with applicable “know-your-customer” and anti-money laundering rules and regulations, including information required by the Patriot Act and the Beneficial Ownership Regulation and (c) the ratings by Moody’s and S&P of the continuing or surviving corporation’s or purchaser’s senior, secured debt shall be at least the higher of (1) Baa3 from Moody’s and BBB- from S&P and (2) the ratings by such rating agencies of the Borrower’s senior, secured debt in effect before the earlier of the occurrence or the public announcement of such event.

1.5Sale and Lease Back Transactions. Enter into any arrangement, directly or indirectly, with any Person whereby it shall sell or transfer any property having fair market value in excess of $10,000,000, real or personal, used or useful in its business, whether now owned or hereafter acquired, and thereafter rent or lease such property or other property that it intends to use for substantially the same purpose or purposes as the property being sold or transferred, except for (a) those transactions described on Schedule 7.5 and (b) any other sale of any fixed or capital assets that is made for cash consideration; provided that, in each case, if such sale and leaseback results in a Capital Lease Obligation, such Capital Lease Obligation is permitted by Section 7.1 and any Lien made the subject of such Capital Lease Obligation is permitted by Section 7.3.

1.6Swap Agreements. Enter into any Swap Agreement, other than Swap Agreements entered into not for speculative purposes (a) to hedge or mitigate risks to which the Borrower and its Subsidiaries are exposed in the conduct of its business or the management of its liabilities (including, without limitation, raw material, commodities, fuel, electricity or other supply costs and currency risks), (b) to effectively cap, collar or exchange interest rates (from fixed to floating rates, from one floating rate to another floating rate or fixed rate or otherwise) with respect to any interest bearing Indebtedness of the Borrower and its Subsidiaries permitted by this Agreement, (c) to swap currency in connection with funding the business of the Borrower and its Subsidiaries in the ordinary course of business or (d) entered into in connection with any A/R Securitization Transaction.

1.7Amendments to FMB Indenture. Amend, supplement, modify or waive the FMB Indenture in any manner that is materially adverse to the Lenders hereunder; provided that the foregoing shall not prohibit the Borrower from supplementing the FMB Indenture in order to provide for the issuance of additional First Mortgage Bonds in accordance with the FMB Indenture or to add property to the Lien of the FMB Indenture.

Section 33.EVENTS OF DEFAULT

If any of the following events shall occur and be continuing on or after the Effective Date:

(a)the Borrower shall fail to pay any principal of the Loans when due in accordance with the terms hereof; or the Borrower shall fail to pay any interest on the Loans, or any other amount payable hereunder or under any other Loan Document, within five Business Days after any such interest or other amount becomes due in accordance with the terms hereof; or

(b)any representation or warranty made or deemed made by the Borrower herein or in any other Loan Document or that is contained in any certificate, document or financial or other statement furnished by it at any time under or in connection with this Agreement or any such other Loan Document shall prove to have been inaccurate in any material respect on or as of the date made or deemed made, unless, as of any date of determination, the facts or circumstances to which such representation or warranty relates have changed with the result that such representation or warranty is true and correct in all material respects on such date; or

(c)the Borrower shall default in the observance or performance of any agreement contained in Section 6.4(a)(i), Section 6.7(a), Section 6.10, Section 7.1, Section 7.2, Section 7.3 or Section 7.4 of this Agreement; or

(d)the Borrower shall default in the observance or performance of any other agreement contained in this Agreement or any other Loan Document (other than as provided in paragraphs (a) through (c) of this Section), and such default shall continue unremedied for a period of 30 days after notice to the Borrower from the Administrative Agent at the request of the Required Lenders; or

(e)the Borrower or any of its Significant Subsidiaries shall (i) default in making any payment of any principal of any Indebtedness (including any

Guarantee Obligation, but excluding the Loans) on the due date with respect thereto (after giving effect to any period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created); or (ii) default in making any payment of any interest on any such Indebtedness beyond the period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created; or (iii) default in the observance or performance of any other agreement or condition relating to any such Indebtedness or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event shall occur or condition exist, the effect of which default or other event or condition is to cause, or (in the case of all Indebtedness other than Indebtedness under any Swap Agreement) to permit the holder or beneficiary of such Indebtedness (or a trustee or agent on behalf of such holder or beneficiary) to cause, with the giving of notice if required, such Indebtedness to become due prior to its stated maturity or (in the case of any such Indebtedness constituting a Guarantee Obligation) to become payable; provided, that a default, event or condition described in clause (i), (ii) or (iii) of this paragraph (e) shall not at any time constitute an Event of Default unless, at such time, one or more defaults, events or conditions of the type described in clauses (i), (ii) and (iii) of this paragraph (e) shall have occurred and be continuing with respect to Indebtedness the outstanding principal amount of which exceeds in the aggregate $200,000,000; provided, further, that unless payment of the Loans hereunder has already been accelerated, if such default shall be cured by the Borrower or such Significant Subsidiary or waived by the holders of such Indebtedness and any acceleration of maturity having resulted from such default shall be rescinded or annulled, in each case, in accordance with the terms of such agreement or instrument, without any modification of the terms of such Indebtedness requiring the Borrower or such Significant Subsidiary to furnish security or additional security therefor, reducing the average life to maturity thereof or increasing the principal amount thereof, or any agreement by the Borrower or such Significant Subsidiary to furnish security or additional security therefor or to issue in lieu thereof Indebtedness secured by additional or other collateral or with a shorter average life to maturity or in a greater principal amount, then any Default hereunder by reason thereof shall be deemed likewise to have been thereupon cured or waived; or

(f)(i) the Borrower or any of its Significant Subsidiaries shall commence any case, proceeding or other action (A) under any existing or future law of any jurisdiction, domestic or foreign, relating to bankruptcy, insolvency, reorganization or relief of debtors, seeking to have an order for relief entered with respect to it, or seeking to adjudicate it as bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding up, liquidation, dissolution, composition or other relief with respect to it or its debts, or (B) seeking appointment of a receiver, trustee, custodian, conservator or other similar official for it or for all or any substantial part of its assets, or the Borrower or any of its Significant Subsidiaries shall make a general assignment for the benefit of its creditors; or (ii) there shall be commenced against the Borrower or any of its Significant Subsidiaries any case, proceeding or other action of a nature referred to in clause (i) above that (A) results in the entry of an order for relief or any such adjudication or appointment or (B) remains undismissed, undischarged or unbonded for a period of 60 days; or (iii) there shall be commenced against the Borrower or any of its Significant Subsidiaries any case, proceeding or other action seeking issuance of a warrant of attachment, execution, distraint or similar process against all or any

substantial part of its assets that results in the entry of an order for any such relief that shall not have been vacated, discharged, or stayed or bonded pending appeal within 60 days from the entry thereof; or (iv) the Borrower or any of its Significant Subsidiaries shall generally not, or shall be unable to, or shall admit in writing its inability to, pay its debts as they become due; or

(g)there occurs any ERISA Event that, individually or in the aggregate, would reasonably be expected to result in a Material Adverse Effect; or

(h)one or more judgments or decrees shall be entered against the Borrower or any of its Significant Subsidiaries by a court of competent jurisdiction involving in the aggregate a liability (not paid or, subject to customary deductibles, fully covered by insurance as to which the relevant insurance company has not denied coverage) of $200,000,000 or more, and all such judgments or decrees shall not have been vacated, discharged, stayed or bonded pending appeal within 45 days from the entry thereof unless, in the case of a discharge, such judgment or decree is due at a later date in one or more payments and the Borrower or such Significant Subsidiary satisfies the obligation to make such payment or payments on or prior to the date such payment or payments become due in accordance with such judgment or decree; or

(i)there shall have occurred a Change of Control; or

(j)any Loan Document, at any time after its execution and delivery and for any reason other than as expressly permitted hereunder or thereunder or satisfaction in full of all the Obligations, ceases to be in full force and effect; or the Borrower contests in any manner in writing the validity or enforceability of any Loan Document; or the Borrower denies in writing that it has any or further liability or obligation under any Loan Document, or purports in writing to revoke, terminate or rescind any Loan Document; or

(k)at any time (i) any Senior Bond shall cease to be outstanding for any reason other than (A) the payment in full of the applicable Tranche relating to such Senior Bond and other obligations then due and owing under the Loan Documents with respect thereto or (B) the payment in full of such Senior Bond, (ii) the Administrative Agent, on behalf of the Lenders, shall cease at any time to be the holder of any Senior Bond for all purposes of the FMB Indenture (unless such Senior Bond is transferred by the Administrative Agent other than in connection with the payment in full of the obligations with respect to such Senior Bond) or (iii) the Lien of the FMB Indenture shall cease to constitute a valid and enforceable Lien on the Mortgaged Property;

then, and in any such event, (A) if such event is an Event of Default specified in clause (i) or (ii) of paragraph (f) above with respect to the Borrower, the Loans (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents shall immediately become due and payable, and (B) if such event is any other Event of Default, either or both of the following actions may be taken: with the consent of the Required Lenders, the Administrative Agent may, or upon the request of the Required Lenders, the Administrative Agent shall, by notice to the Borrower, declare the Loans (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents to be due and payable forthwith, whereupon the same shall immediately become due and payable. Except as expressly provided above in this

Section, presentment, demand, protest and all other notices of any kind are hereby expressly waived by the Borrower.

Section 34.THE AGENTS

1.1Appointment and Authority. Each of the Lenders hereby irrevocably appoints JPMorgan Chase Bank, N.A. to act on its behalf as the Administrative Agent hereunder and under the other Loan Documents and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. The provisions of this Section 9 are solely for the benefit of the Agents, the Lenders and the Borrower shall not have rights as a third-party beneficiary of any of such provisions (other than with respect to the Borrower’s rights under Sections 9.9(a) and (b)). It is understood and agreed that the use of the term “agent” herein or in any other Loan Documents (or any other similar term) with reference to any Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law. Instead such term is used as a matter of market custom, and is intended to create or reflect only an administrative relationship between contracting parties.

1.2Delegation of Duties. The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub-agents appointed by it. The Administrative Agent, and any such sub-agent may each perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Section shall apply to any such sub-agent and to the Related Parties of the Administrative Agent, and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent. The Administrative Agent shall not be responsible for the negligence or misconduct of any sub-agents except to the extent that a court of competent jurisdiction determines in a final and nonappealable judgment that the Administrative Agent acted with gross negligence or willful misconduct in the selection of such sub-agents.

1.3Exculpatory Provisions.

(a)No Agent shall have any duties or obligations except those expressly set forth herein and in the other Loan Documents, and its duties hereunder shall be administrative in nature. Without limiting the generality of the foregoing, no Agent:

Section 35.shall be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;

Section 36.shall have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that an Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein or in the other Loan Documents); provided that no Agent shall be required to take any action that, in its opinion or the opinion of its counsel, may expose such Agent to liability or that is contrary to any Loan Document or

applicable law, including for the avoidance of doubt any action that may be in violation of the automatic stay under any Debtor Relief Law or that may effect a forfeiture, modification or termination of property of a Defaulting Lender in violation of any Debtor Relief Law; and

Section 37.shall, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as an Agent or any of its Affiliates in any capacity.

(a)No Agent shall be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as such Agent shall believe in good faith shall be necessary, under the circumstances as provided in Sections 10.1 and 8), or (ii) in the absence of its own gross negligence or willful misconduct as determined by a court of competent jurisdiction by final and nonappealable judgment.

(b)No Agent shall be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default or Event of Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Section 5 or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to such Agent.

1.2Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, Internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of a Loan, that by its terms must be fulfilled to the satisfaction of a Lender, the Administrative Agent may presume that such condition is satisfactory to such Lender unless the Administrative Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

1.3Notice of Default. The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default unless the Administrative Agent has received notice from a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the

Administrative Agent receives such a notice, the Administrative Agent shall give notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Required Lenders (or, if so specified by this Agreement, all Lenders); provided that unless and until such Agent shall have received such directions, such Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders.

1.4Non-Reliance on Agents and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the business, operations, property, condition (financial or otherwise), prospects or creditworthiness of the Borrower or any of its Affiliates that may come into the possession of such Agent or any of its officers, directors, employees, agents, attorneys in fact or Affiliates.

1.5Indemnification. The Lenders agree to indemnify each Agent in its capacity as such (to the extent not reimbursed by the Borrower and without limiting the obligation of the Borrower to do so), ratably according to their respective Percentages in effect on the date on which indemnification is sought under this Section (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with such Percentages immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time (whether before or after the payment of the Loans) be imposed on, incurred by or asserted against such Agent in any way relating to or arising out of, the Commitments, this Agreement, any of the other Loan Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by such Agent under or in connection with any of the foregoing; provided that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements that are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from such Agent’s gross negligence or willful misconduct.

1.6Agent in Its Individual Capacity. Each Person serving as an Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Agent, and the terms “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include such Person serving as an Agent hereunder

in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, own securities of, act as the financial advisor or in any other advisory capacity for, and generally engage in any kind of business with, the Borrower or any Subsidiary or other Affiliate thereof as if such Person were not an Agent hereunder and without any duty to account therefor to the Lenders.

1.7Successor Agents.

(a)The Administrative Agent may resign upon 10 days’ notice to the Lenders and the Borrower. If the Administrative Agent shall so resign under this Agreement and the other Loan Documents, then the Required Lenders shall appoint from among the Lenders a successor agent for the Lenders, which successor agent shall (unless an Event of Default under Section 8(f) with respect to the Borrower shall have occurred and be continuing) be subject to approval by the Borrower (which approval shall not be unreasonably withheld, conditioned or delayed), whereupon such successor agent shall succeed to the rights, powers and duties of the Administrative Agent and the term “Administrative Agent” shall mean such successor agent effective upon such appointment and approval, and the former Agent’s rights, powers and duties as Administrative Agent shall be terminated, without any other or further act or deed on the part of such former Agent or any of the parties to this Agreement or any holders of the Loans. If no successor agent has accepted appointment as Administrative Agent by the date that is 10 days following a retiring Agent’s notice of resignation (the “Resignation Effective Date”), the retiring Agent’s resignation shall nevertheless thereupon become effective, and the Lenders shall assume and perform all of the duties of the Administrative Agent hereunder until such time, if any, as the Required Lenders appoint a successor agent as provided for above. After any retiring Agent’s resignation as Administrative Agent the provisions of Section 9.7 shall inure to its benefit as to any actions taken or omitted to be taken by it while it was an Agent under this Agreement and the other Loan Documents.

(b)If the Person serving as Administrative Agent is a Defaulting Lender pursuant to clause (e) of the definition thereof, the Required Lenders may, to the extent permitted by applicable law, by notice in writing to the Borrower and such Person remove such Person as Administrative Agent and, shall appoint a successor, subject to the approval of the Borrower (unless an Event of Default under Section 8(f) with respect to the Borrower shall have occurred and be continuing), which approval shall not be unreasonably withheld, conditioned or delayed. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days (or such earlier day as shall be agreed by the Required Lenders) (the “Removal Effective Date”), then such removal shall nonetheless become effective in accordance with such notice on the Removal Effective Date.

(c)With effect from the Resignation Effective Date or the Removal Effective Date (as applicable) (i) the retiring or removed Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents (except that in the case of any Senior Bond held by the Administrative Agent on behalf of the Lenders, the retiring or removed Administrative Agent shall continue to hold such Senior Bond in its name until such time as a successor Administrative Agent is appointed) and (ii) except for any indemnity payments or other amounts then owed to the retiring or removed Administrative Agent, all payments, communications and determinations

provided to be made by, to or through the Administrative Agent shall instead be made by or to each Lender directly, until such time, if any, as the Required Lenders appoint a successor Administrative Agent as provided for above. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring or removed Agent (other than any rights to indemnity payments or other amounts owed to the retiring or removed Agent as of the Resignation Effective Date or the Removal Effective Date (as applicable)), and the retiring or removed Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents. The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring or removed Agent’s resignation or removal hereunder and under the other Loan Documents, the provisions of this Section and Sections 2.17 and 10.5 shall continue in effect for the benefit of such retiring or removed Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring or removed Agent was acting as Agent.

1.8Documentation Agents and Syndication Agents. None of the Documentation Agents or the Syndication Agents shall have any duties or responsibilities hereunder in its capacity as such.

1.9Administrative Agent May File Proofs of Claim. In case of the pendency of any proceeding under any Debtor Relief Law, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered (but not obligated) by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Obligations that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Sections 2.6, 2.17 and 10.5) allowed in such judicial proceeding; and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Sections 2.6, 2.17 and 10.5.

1.10Certain ERISA Matters.

(a)Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:

Section 38.such Lender is not using “plan assets” (within the meaning of Section 3(42) of ERISA or otherwise) of one or more Benefit Plans with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments or this Agreement,

Section 39.the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement,

Section 40.(A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loans, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement, or

Section 41.such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

(a)In addition, unless either (1) sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or (2) a Lender has provided another representation, warranty and covenant in accordance with sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that the Administrative Agent is not a fiduciary with respect to the assets of such Lender involved in such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Loan Document or any documents related hereto or thereto).

1.2Erroneous Payment.

(a)If the Administrative Agent notifies a Lender or any Person who has received funds on behalf of a Lender, such Lender (any such Lender or other recipient, a “Payment Recipient”) that the Administrative Agent has determined in its sole discretion (whether or not after receipt of any notice under immediately succeeding clause (b)) that any funds received by such Payment Recipient from the Administrative Agent or any of its Affiliates were erroneously transmitted to, or otherwise erroneously or mistakenly received by, such Payment Recipient (whether or not known to such Lender or other Payment Recipient on its behalf) (any such funds, whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise, individually and collectively, an “Erroneous Payment”) and demands the return of such Erroneous Payment (or a portion thereof), such Erroneous Payment shall at all times remain the property of the Administrative Agent and shall be segregated by the Payment Recipient and held in trust for the benefit of the Administrative Agent, and such Lender shall (or, with respect to any Payment Recipient who received such funds on its behalf, shall cause such Payment Recipient to) promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such Erroneous Payment (or portion thereof) as to which such a demand was made, in same day funds (in the currency so received), together with interest thereon in respect of each day from and including the date such Erroneous Payment (or portion thereof) was received by such Payment Recipient to the date such amount is repaid to the Administrative Agent in same day funds at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect. A notice of the Administrative Agent to any Payment Recipient under this clause (a) shall be conclusive, absent manifest error.

(b)Without limiting immediately preceding clause (a), each Lender, or any Person who has received funds on behalf of a Lender, such Lender, hereby further agrees that if it receives a payment, prepayment or repayment (whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise) from the Administrative Agent (or any of its Affiliates) (x) that is in a different amount than, or on a different date from, that specified in a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates) with respect to such payment, prepayment or repayment, (y) that was not preceded or accompanied by a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates), or (z) that such Lender, or other such recipient, otherwise becomes aware was transmitted, or received, in error or by mistake (in whole or in part) in each case:

(i)(A) in the case of immediately preceding clauses (x) or (y), an error shall be presumed to have been made (absent written confirmation from the Administrative Agent to the contrary) or (B) an error has been made (in the case of immediately preceding clause (z)), in each case, with respect to such payment, prepayment or repayment; and

(ii)such Lender shall (and shall cause any other recipient that receives funds on its respective behalf to) promptly (and, in all events, within one Business Day of its knowledge of such error) notify the Administrative Agent of its receipt of such payment, prepayment or repayment, the details thereof (in reasonable detail) and that it is so notifying the Administrative Agent pursuant to this Section 9.13(b), and upon demand from the Administrative Agent, it shall promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such payment, prepayment or repayment as to which such a demand was made in same day funds, together with interest thereon in respect of each day from and including the date such payment, prepayment or repayment was received by such Lender to the date such amount is repaid to the Administrative Agent at the greater of the NYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect.

(c)Each Lender hereby authorizes the Administrative Agent to set off, net and apply any and all amounts at any time owing to such Lender under any Loan Document, or otherwise payable or distributable by the Administrative Agent to such Lender from any source, against any amount due to the Administrative Agent under immediately preceding clause (a) or under the indemnification provisions of this Agreement.

(d)The Borrower hereby agrees that in the event an Erroneous Payment (or portion thereof) are not recovered from any Lender that has received such Erroneous Payment (or portion thereof) for any reason, the Administrative Agent shall be subrogated to all the rights of such Lender with respect to such amount.

(e)The parties hereto agree that an Erroneous Payment shall not pay, prepay, repay, discharge or otherwise satisfy any Obligations owed by the Borrower, except, in each case, to the extent such Erroneous Payment is, and solely with respect to the amount of such Erroneous Payment that is, comprised of funds received by the Administrative Agent from the Borrower for the purpose of making such Erroneous Payment.

(f)To the extent permitted by applicable law, no Payment Recipient shall assert any right or claim to an Erroneous Payment, and hereby waives, and is deemed to waive, any claim, counterclaim, defense or right of set-off or recoupment with respect to any demand, claim or counterclaim by the Administrative Agent for the return of any Erroneous Payment received, including without limitation waiver of any defense based on “discharge for value” or any similar doctrine.

(g)Each party’s obligations, agreements and waivers under this Section 9.13 shall survive the resignation or replacement of the Administrative Agent, any transfer of rights or obligations by, or the replacement of a Lender, the termination of the Commitments and/or the repayment, satisfaction or discharge of all Obligations (or any portion thereof) under any Loan Document.

Section 42.MISCELLANEOUS

1.1Amendments and Waivers. Subject to Section 2.13(b) and (c), neither this Agreement, any other Loan Document, nor any terms hereof or thereof may be amended, supplemented or modified except in accordance with the provisions of this Section 10.1. The Required Lenders and the Borrower may, or, with the written consent of the Required Lenders, the Administrative Agent and the Borrower may, from time to time, (a) enter into written amendments, supplements or modifications hereto and to the other Loan Documents for the purpose of adding any provisions to this Agreement or the other Loan Documents or changing in any manner the rights of the Lenders or of the Borrower hereunder or thereunder or (b) waive, on such terms and conditions as the Required Lenders or the Administrative Agent, as the case may be, may specify in such instrument, any of the requirements of this Agreement or the other Loan Documents or any Default or Event of Default and its consequences; provided, however, that no such waiver and no such amendment, supplement or modification shall:

Section 43.forgive the principal amount or extend the final scheduled date of maturity of any Loan, reduce the stated rate of any interest or fee payable hereunder (except in connection with the waiver of applicability of any post-default increase in interest rates (which waiver shall be effective with the consent of the Required Lenders)) or extend the scheduled date of any payment thereof, in each case without the written consent of each Lender directly affected thereby;

Section 44.eliminate or reduce the voting rights of any Lender under this Section 10.1 or Section 10.6(a)(i) without the written consent of such Lender;

Section 45.reduce any percentage specified in the definition of Required Lenders without the written consent of all Lenders;

Section 46.amend, modify or waive any provision of Section 2.14, Section 10.07 (Application of Money Collected) of the FMB Indenture or any similar provision in the Loan Documents related to pro rata treatment without the consent of each Lender directly affected thereby;

Section 47.amend, modify or waive any provision of Section 9 without the written consent of the Administrative Agent;

Section 48.[reserved];

Section 49.amend, modify or waive any provision of Section 5.1 without the written consent of all the Lenders;

Section 50.amend, modify or waive any provision of Section 2.8(b) without the written consent of each Lender affected thereby;

Section 51.amend or modify any provision in any Loan Document in a manner that by its terms affects the rights or duties under this Agreement of the Lenders of one Tranche (but not the other Tranche), without the prior written consent of the requisite number or percentage in interest of each affected Tranche of Lenders that would be required to consent thereto under this Section if such Tranche of Lenders were the only Tranche of Lenders hereunder at the time; or

Section 52.instruct the Administrative Agent to vote the Senior Bonds in favor of the release of all or substantially all of the Mortgaged Property without the written consent of all the Lenders.

Any such waiver and any such amendment, supplement or modification shall apply equally to each of the Lenders and shall be binding upon the Borrower, the Lenders, the Administrative Agent and all future holders of the Loans. In the case of any waiver, the Borrower, the Lenders and the Administrative Agent shall be restored to their former position and rights hereunder and under the other Loan Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; but no such waiver shall extend to any subsequent or other Default or Event of Default, or impair any right consequent thereon.

Notwithstanding anything to the contrary contained in this Section 10.1, if the Administrative Agent and the Borrower acting together identify any ambiguity, omission, mistake, typographical error or other defect in any provision of this Agreement or any other Loan Document, then the Administrative Agent and the Borrower shall be permitted to amend, modify or supplement such provision to cure such ambiguity, omission, mistake, typographical error or other defect, and any such amendment, modification or supplement shall become effective without any further action or consent of any other party to this Agreement.

If the Required Lenders shall have approved any amendment which requires the consent of all of the Lenders, the Borrower shall be permitted to replace any non-consenting Lender with another financial institution, provided that, (i) the replacement financial institution shall purchase at par, all Loans and other amounts owing to such replaced Lender on or prior to the date of replacement, (ii) the Borrower shall be liable to such replaced Lender under Section 2.17 if any Eurodollar Loan owing to such replaced Lender shall be purchased other than on the last day of the Interest Period relating thereto (as if such purchase constituted a prepayment of such Loans), (iii) such replacement financial institution, if not already a Lender, shall be reasonably satisfactory to the Administrative Agent, (iv) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 10.6 (provided that the Borrower shall be obligated to pay the registration and processing fee referred to therein) (for the avoidance of doubt, such replacement shall be effective subject to the conditions in the other clauses set forth in this proviso, regardless of whether such replaced Lender enters into an Assignment and Assumption) and (v) any such replacement shall not be deemed to be a waiver of any rights the Borrower, the Administrative Agent, or any other Lender shall have against the replaced Lender.

Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to approve or disapprove any amendment, supplement, modification, waiver or consent hereunder (and any amendment, supplement, modification, waiver or consent which by its terms requires the consent of all Lenders or each affected Lender may be effected with the consent of the applicable Lenders other than Defaulting Lenders), except that (i) any reduction of the amount of principal or interest owed to such Defaulting Lender shall, in each case, require the consent of such Defaulting Lender, and (ii) a Defaulting Lender’s Percentage shall be taken into consideration along with the Percentage of non-Defaulting Lenders when voting to approve or disapprove any waiver, amendment or modification that by its terms affects any Defaulting Lender more adversely than other affected Lenders.

1.1Notices.

(a)All notices, requests and demands to or upon the respective parties hereto to be effective shall be in writing (including by telecopy), and, unless otherwise expressly provided herein, shall be deemed to have been duly given or made when delivered during the recipient’s normal business hours, or three Business Days after being deposited in the mail, postage prepaid, or, in the case of telecopy notice, when received during the recipient’s normal business hours, addressed as follows in the case of the Borrower and the Administrative Agent, and as set forth in an administrative questionnaire delivered to the Administrative Agent in the case of the Lenders, or to such other address as may be hereafter notified by the respective parties hereto:

Borrower:    Pacific Gas and Electric Company
c/o PG&E Corporation
P.O. Box 770000
San Francisco, California 94177
Attention: Treasurer
Telecopy: (415) 973-8968
Telephone: (415) 973-8956

with a copy to:    Pacific Gas and Electric Company
c/o PG&E Corporation
P.O. Box 770000
San Francisco, California 94177
Attention: General Counsel
Telecopy: (415) 973-5520

Administrative Agent:    JPMorgan Chase Bank, N.A.
500 Stanton Christiana Road
NCC 5, 1st Floor
Newark, DE 19713-2107
Attention: Mary Crews
Telecopy: (302) 634-5758
Telephone: (302) 634-1417
Email: mary.crews@jpmorgan.com

provided that any notice, request or demand to or upon the Administrative Agent or any Lender shall not be effective until received.

(b)Notices and other communications to the Administrative Agent or the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Section 2 unless otherwise agreed by the Administrative Agent and each Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c)Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed

receipt by the intended recipient, at its e-mail address as described in the foregoing clause (i), of notification that such notice or communication is available and identifying the website address therefor; provided that, for both clauses (i) and (ii) above, if such notice, email or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient.

(d)(i) The Borrower agrees that the Administrative Agent may, but shall not be obligated to, make the Communications (as defined below) available to the Lenders by posting the Communications on Debt Domain, Intralinks, Syndtrak or a substantially similar electronic transmission system (the “Platform”).

Section 53.The Platform is provided “as is” and “as available.” The Agent Parties (as defined below) do not warrant the adequacy of the Platform and expressly disclaim liability for errors or omissions in the Communications. No warranty of any kind, express, implied or statutory, including, without limitation, any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects, is made by any Agent Party in connection with the Communications or the Platform. In no event shall the Administrative Agent or any of its Related Parties (collectively, the “Agent Parties”) have any liability to the Borrower, any Lender or any other Person or entity for damages of any kind, including, without limitation, direct or indirect, special, incidental or consequential damages, losses or expenses (whether in tort, contract or otherwise) arising out of the Borrower’s or the Administrative Agent’s transmission of Communications through the Platform, except to the extent such liability resulted from the gross negligence or willful misconduct of the Administrative Agent or any of its Related Parties as determined by a court of competent jurisdiction in a final non-appealable judgment. “Communications” means, collectively, any notice, demand, communication, information, document or other material provided by or on behalf of the Borrower pursuant to any Loan Document or the transactions contemplated therein which is distributed to the Administrative Agent or any Lender by means of electronic communications pursuant to this Section, including through the Platform.

1.1No Waiver; Cumulative Remedies. No failure to exercise and no delay in exercising, on the part of the Administrative Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Loan Documents shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.

1.2Survival of Representations and Warranties. All representations and warranties made hereunder, in the other Loan Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans hereunder.

1.3Payment of Expenses and Taxes. The Borrower agrees (a) to pay or reimburse the Administrative Agent and the Lenders for all their respective reasonable out of pocket costs and expenses incurred in connection with the development, preparation and execution of, and any amendment, supplement or

modification to, this Agreement and the other Loan Documents and any other documents prepared in connection herewith or therewith, and the consummation of the transactions contemplated hereby and thereby, including the reasonable fees and disbursements of only one joint counsel and one joint special California counsel and, if necessary, one joint local counsel in each other relevant jurisdiction to the Administrative Agent and the Lenders (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons) and filing and recording fees and expenses, with statements with respect to the foregoing to be submitted to the Borrower prior to the Effective Date (in the case of amounts to be paid on the Effective Date) and from time to time thereafter on a quarterly basis or such other periodic basis as the Administrative Agent shall deem appropriate, (b) to pay or reimburse each Lender and the Administrative Agent for all its costs and expenses incurred in connection with the enforcement or preservation of its rights under this Agreement, the other Loan Documents and any such other documents, including the reasonable fees and disbursements of only one joint counsel, one joint special California counsel and, if necessary, one local counsel in each other relevant jurisdiction to the Administrative Agent and the Lenders (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons), and (c) to pay, indemnify, and hold each Lender, the Administrative Agent and their respective Affiliates and their respective officers, directors, employees and agents (each, an “Indemnitee”) harmless from and against any and all other liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever whether brought by the Borrower or any other Person, with respect to the execution, delivery, enforcement and performance of, or arising out of or in connection with, this Agreement, the other Loan Documents and any such other documents, including any of the foregoing relating to the use of proceeds of the Loans or the violation of, noncompliance with or liability under, any Environmental Law directly or indirectly relating to the Borrower, its Significant Subsidiaries or any of the facilities and properties owned, leased or operated by the Borrower or its Significant Subsidiaries and the reasonable, documented and invoiced fees and expenses of one joint counsel and one joint special California counsel and, if necessary, one joint local counsel in each other relevant jurisdiction to the applicable Indemnitee (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons), in connection with claims, actions or proceedings by any Indemnitee against the Borrower under any Loan Document (all the foregoing in this clause (c), collectively, the “Indemnified Liabilities”), provided, that the Borrower shall have no obligation hereunder to any Indemnitee with respect to Indemnified Liabilities to the extent such Indemnified Liabilities resulted from, as determined in a final non-appealable judgment by a court of competent jurisdiction, (x) the gross negligence, bad faith or willful misconduct of such Indemnitee or its Affiliates, (y) the material breach of such Indemnitee’s funding obligations hereunder or (z) a dispute amongst one or more Lenders not arising from the Borrower’s breach of its obligations under the Loan Documents (other than a dispute involving a claim against an Indemnitee for its acts or omissions in its capacity as an arranger, bookrunner, agent or similar role in respect of the Loan Agreement, except, to the extent such acts or omissions are determined by a court of competent jurisdiction by a final and non-appealable judgment to have constituted the gross negligence, bad faith or willful misconduct of such Indemnitee in such capacity). Without limiting the foregoing, and to the extent permitted by applicable law, the Borrower agrees not to assert and to cause

its Significant Subsidiaries not to assert, and hereby waives and agrees to cause its Significant Subsidiaries to waive, all rights for contribution or any other rights of recovery with respect to all claims, demands, penalties, fines, liabilities, settlements, damages, costs and expenses of whatever kind or nature, under or related to Environmental Laws, that any of them might have by statute or otherwise against any Indemnitee. All amounts due under this Section 10.5 shall be payable not later than 30 days after written demand therefor, subject to the Borrower’s receipt of reasonably detailed invoices. Statements payable by the Borrower pursuant to this Section 10.5 shall be submitted to Treasurer (Telephone No. (415) 817-8199/(415) 267-7000) (Telecopy No. (415) 267-7265/7268), at the address of the Borrower set forth in Section 10.2(a) with a copy to Chief Counsel, Corporate (Telephone No. (415) 817-8200) (Telecopy No. (415) 817-8225), at the address of the Borrower set forth in Section 10.2(a), or to such other Person or address as may be hereafter designated by the Borrower in a written notice to the Administrative Agent. The agreements in this Section 10.5 shall survive for two years after repayment of the Loans and all other amounts payable hereunder. This Section 10.5 shall not apply with respect to Taxes, other than Taxes that represent claims, damages, losses, liabilities, costs or expenses arising from non-Tax claims.

1.4Successors and Assigns; Participations and Assignments.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 10.6.

(b)(i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees (each, an “Assignee”) other than a Defaulting Lender, any Subsidiary of a Defaulting Lender, any natural person (or holding company, investment vehicle or trust for, or owned or operated by or for the primary benefit of, one or more natural persons), the Borrower or any of the Borrower’s Affiliates or Subsidiaries, all or a portion of its rights and obligations under this Agreement (including all or a portion of the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld or delayed) of:

(A)the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender (or an Affiliate of any Lender) or an Approved Fund or, if an Event of Default under Section 8(a), (e) or (f) has occurred and is continuing, any other Person, and providedfurther, that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within ten (10) Business Days after having received notice thereof from the assigning Lender (with a copy to the Administrative Agent); and

(B)the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment of any Loans to an Assignee that is a Lender (or an Affiliate of a Lender) immediately prior to giving effect to such assignment.

Section 54.Assignments shall be subject to the following additional conditions:

(A)except in the case of an assignment to a Lender, an Eligible Assignee that is an Affiliate of any Lender or an assignment of the entire remaining amount of the assigning Lender’s Loans, the amount of the Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $10,000,000 (or, if such Assignee is an Eligible Assignee that is an Affiliate of a Lender, $5,000,000) unless each of the Borrower and the Administrative Agent otherwise consent, provided that (1) no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing and (2) with respect to any Lender party to this Agreement on the Effective Date, such amounts shall be aggregated in respect of such Lender and any Affiliate of such Lender that is an Eligible Assignee;

(B)the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; and

(C)the Assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an administrative questionnaire.

In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the Assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Loans previously requested but not funded by the Defaulting Lender, to each of which the applicable Assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent or any Lender hereunder (and interest accrued thereon) and (y) acquire (and fund as appropriate) its full pro rata share of all Loans in accordance with its Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable law without compliance with the provisions of this paragraph, then the Assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

Section 55.Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) below, from and after the effective date specified in each Assignment and Assumption the Assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, shall have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.15, 2.16, 2.17 and 10.5 but shall be subject to the limitations set forth therein); provided, that except to the extent otherwise expressly agreed by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from the Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 10.6 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section.

Section 56.The Administrative Agent, acting for this purpose as a non-fiduciary agent of the Borrower (and such agency being solely to establish that the relevant obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations), shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, in the absence of manifest error, and the Borrower, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

Section 57.Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an Assignee, the Assignee’s completed administrative questionnaire (unless the Assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this Section and any written consent to such assignment required by paragraph (b) of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

(a)(i) Any Lender may, without the consent of the Borrower or the Administrative Agent, sell participations to one or more banks or other entities (other than a Defaulting Lender or the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any

amendment, modification or waiver of any provision of this Agreement; provided that such agreement may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver that (1) requires the consent of each Lender directly affected thereby pursuant to the proviso to the second sentence of Section 10.1 and (2) directly affects such Participant. Subject to paragraph (c)(ii) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.15, 2.16 and 2.17 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section.

Section 58.Notwithstanding anything to the contrary herein, a Participant shall not be entitled to receive any greater payment under Section 2.15 or 2.16 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent to such greater payments. Any Participant that is a Foreign Lender shall not be entitled to the benefits of Section 2.16 unless such Participant complies with Section 2.16(e).

Section 59.Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any loans or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such loan or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(a)Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central bank having jurisdiction over such Lender, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or Assignee for such Lender as a party hereto.

(b)The Borrower, upon receipt of written notice from the relevant Lender, agrees to issue Notes to any Lender requiring Notes to facilitate transactions of the type described in paragraph (d) above.

(c)Notwithstanding the foregoing, any Conduit Lender may assign any or all of the Loans it may have funded hereunder to its designating Lender without the consent of the Borrower or the Administrative Agent and without regard to the limitations set forth in Section 10.6(b). Each of the Borrower, each Lender and the Administrative Agent hereby confirms that it will not institute against a Conduit Lender or join any other Person in instituting against a Conduit Lender any bankruptcy, reorganization, arrangement, insolvency or

liquidation proceeding under any state bankruptcy or similar law, for one year and one day after the payment in full of the latest maturing commercial paper note issued by such Conduit Lender; provided, however, that each Lender designating any Conduit Lender hereby agrees to indemnify, save and hold harmless each other party hereto for any loss, cost, damage, expense, obligations, penalties, actions, judgments, suits or any kind whatsoever arising out of its inability to institute such a proceeding against such Conduit Lender during such period of forbearance.

(d)Notwithstanding anything to the contrary in this Section, none of the Agents, in their capacity as Lenders, will assign without the consent of the Borrower, prior to the Effective Date, any of the Commitments held by them on the Effective Date.

(e)Notwithstanding anything to the contrary in this Section 10.6, for the avoidance of doubt, Goldman Sachs Bank USA may assign any amount of its Loans hereunder to Goldman Sachs Lending Partners LLC (or vice versa) without the prior written consent of any other Person.

1.2Adjustments; Set off.

(a)Except to the extent that this Agreement expressly provides for payments to be allocated to a particular Lender, if any Lender (a “Benefitted Lender”) shall receive any payment of all or part of the Obligations owing to it hereunder, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set off, pursuant to events or proceedings of the nature referred to in Section 8(f), or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender, if any, in respect of the Obligations owing to such other Lender hereunder, such Benefitted Lender shall purchase for cash from the other Lenders a participating interest in such portion of the Obligations owing to each such other Lender hereunder, or shall provide such other Lenders with the benefits of any such collateral, as shall be necessary to cause such Benefitted Lender to share the excess payment or benefits of such collateral ratably with each of the Lenders; provided, however, that if all or any portion of such excess payment or benefits is thereafter recovered from such Benefitted Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest.

(b)In addition to any rights and remedies of the Lenders provided by law, including other rights of set-off, each Lender shall have the right, without prior notice to the Borrower, any such notice being expressly waived by the Borrower to the extent permitted by applicable law, upon any amount becoming due and payable by the Borrower hereunder (whether at the stated maturity, by acceleration or otherwise), after any applicable grace period, to set off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch, Affiliate or agency thereof to or for the credit or the account of the Borrower; provided, that in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 2.20 and,

pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the Obligations owing to such Defaulting Lender as to which it exercised such right of setoff. Each Lender agrees promptly to notify the Borrower and the Administrative Agent after any such setoff and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such setoff and application.

1.3Counterparts; Electronic Execution; Binding Effect. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Agreement by facsimile transmission, emailed pdf. or any other electronic means that reproduces an image of the actual executed signature page shall be effective as delivery of an original executed counterpart hereof. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Agreement and the transactions contemplated hereby shall be deemed to include an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act; provided that nothing herein shall require the Administrative Agent to accept electronic signatures in any form or format without its prior written consent. Without limiting the generality of the foregoing, the Borrower hereby (i) agrees that, for all purposes, including without limitation, in connection with any workout, restructuring, enforcement of remedies, bankruptcy proceedings or litigation among the Administrative Agent and the Lenders, electronic images of this Agreement or any other Loan Documents (in each case, including with respect to any signature pages thereto) shall have the same legal effect, validity and enforceability as any paper original, and (ii) waives any argument, defense or right to contest the validity or enforceability of the Loan Documents based solely on the lack of paper original copies of any Loan Documents, including with respect to any signature pages thereto. This Agreement shall become binding on the parties hereto when it shall have been executed by the Administrative Agent and the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

1.4Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. Without limiting the foregoing provisions of this Section 10.9, if and to the extent that the enforceability of any provisions in this Agreement

relating to Defaulting Lenders shall be limited by Debtor Relief Laws, as determined in good faith by the Administrative Agent, as applicable, then such provisions shall be deemed to be in effect only to the extent not so limited.

1.5Integration. This Agreement and the other Loan Documents represent the entire agreement of the Borrower, the Administrative Agent, and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Administrative Agent, or any Lender relative to the subject matter hereof not expressly set forth or referred to herein or in the other Loan Documents.

1.6GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

1.7Submission To Jurisdiction; Waivers. The Borrower hereby irrevocably and unconditionally:

(a)submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Loan Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non-exclusive jurisdiction of the United States District Court for the Southern District of New York sitting in the Borough of Manhattan (or if such court lacks subject matter jurisdiction, the Supreme Court of the State of New York sitting in the Borough of Manhattan), and any appellate court from any thereof;

(b)consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c)agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to the Borrower at its address set forth in Section 10.2(a) or at such other address of which the Administrative Agent shall have been notified pursuant thereto;

(d)agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction; and

(e)waives, to the maximum extent not prohibited by law, and agrees not to assert any right it may have to claim or recover in any legal action or proceeding relating to this Agreement or any other Loan Document any special, exemplary, punitive or consequential damages.

NOTHING IN THIS AGREEMENT OR IN ANY OTHER LOAN DOCUMENT SHALL AFFECT ANY RIGHT THAT THE ADMINISTRATIVE AGENT OR ANY LENDER MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN

DOCUMENT AGAINST THE BORROWER OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

1.8Acknowledgments. The Borrower hereby acknowledges that:

(a)it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents;

(b)none of the Administrative Agent or any Lender has any fiduciary relationship with or duty to the Borrower arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between Administrative Agent and Lenders, on one hand, and the Borrower, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

(c)no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrower and the Lenders.

1.9Confidentiality. Each of the Administrative Agent and each Lender agrees to keep confidential in accordance with such party’s customary practices (and in any event in compliance with applicable law regarding material non-public information) all non-public information provided to it by the Borrower, the Administrative Agent or any Lender pursuant to or in connection with this Agreement that is designated by the provider thereof as confidential; provided that nothing herein shall prevent the Administrative Agent or any Lender from disclosing any such information (a) to the Administrative Agent, any other Lender or any Affiliate thereof, (b) subject to an agreement to comply with the provisions of this Section or substantially equivalent provisions, to any actual or prospective Transferee, any direct or indirect counterparty to any Swap Agreement (or any professional advisor to such counterparty) or any credit insurance providers, (c) to its employees, directors, agents, attorneys, service providers, accountants and other professional advisors or those of any of its Affiliates (as long as such attorneys, service providers, accountants and other professional advisors are directed to comply with confidentiality requirements substantially equivalent to this Section), (d) upon the request or demand of any Governmental Authority, (e) in response to any order of any court or other Governmental Authority or as may otherwise be required pursuant to any Requirement of Law, (f) if requested or required to do so in connection with any litigation or similar proceeding, (g) that has been publicly disclosed, (h) to the National Association of Insurance Commissioners or any similar organization or any nationally recognized rating agency that requires access to information about a Lender’s investment portfolio in connection with ratings issued with respect to such Lender, (i) in connection with the exercise of any remedy hereunder or under any other Loan Document, (j) any rating agency in connection with rating of the Borrower or its Subsidiaries or the credit facilities provided hereunder or (k) to the extent such information (i) becomes available to the Administrative Agent, any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower or its Subsidiaries or (ii) is independently discovered or developed by a party hereto without utilizing any information received from the Borrower or its Subsidiaries or violating the terms of this Section 10.14, provided that, in the case of clauses (d), (e) and (f) of this Section 10.14, with the exception of disclosure to bank regulatory authorities, the

Borrower (to the extent legally permissible) shall be given prompt prior notice so that it may seek a protective order or other appropriate remedy.

1.10WAIVERS OF JURY TRIAL. TO THE FULLEST EXTENT PERMITTED BY LAW, THE BORROWER, THE ADMINISTRATIVE AGENT AND THE LENDERS HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

1.11USA Patriot Act; Beneficial Ownership Regulation. Each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Patriot Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Patriot Act.

1.12Judicial Reference. If any action or proceeding is filed in a court of the State of California by or against any party hereto in connection with any of the transactions contemplated by this Agreement or any other Loan Document, (i) the court shall, and is hereby directed to, make a general reference pursuant to California Code of Civil Procedure Section 638 to a referee (who shall be a single active or retired judge) to hear and determine all of the issues in such action or proceeding (whether of fact or of law) and to report a statement of decision, provided that at the option of any party to such proceeding, any such issues pertaining to a “provisional remedy” as defined in California Code of Civil Procedure Section 1281.8 shall be heard and determined by the court, and (ii) without limiting the generality of Section 10.5, the Borrower shall be solely responsible to pay all fees and expenses of any referee appointed in such action or proceeding.

1.13No Advisory or Fiduciary Responsibility. In connection with all aspects of each transactions contemplated hereby (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document), the Borrower acknowledges and agrees that: (i) (A) the arranging and other services regarding this Agreement provided by the Agents, the Arrangers and the Lenders are arm’s-length commercial transactions between the Borrower, on the one hand, and the Agents, the Arrangers and the Lenders, on the other hand, (B) the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate, and (C) the Borrower is capable of evaluating, and understands and accepts, the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents; (ii) (A) each Agent, Arranger and Lender is and has been acting solely as a principal and, except as expressly agreed in writing by the relevant parties, has not been, is not, and will not be acting as an advisor, agent or fiduciary for the Borrower or any other Person and (B) none of the Agents, Arrangers or Lenders has any obligation to the Borrower or any of its Affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents; and (iii) the Agents, the Arrangers and the Lenders and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its Affiliates, and none of the Agents, Arrangers or Lenders has any obligation to disclose any of such interests to the Borrower or its Affiliates. To the fullest extent permitted by

law, the Borrower hereby waives and releases any claims that it may have against the Agents, the Arrangers and the Lenders with respect to any breach or alleged breach of agency or fiduciary duty in connection with any aspect of any transaction contemplated hereby other than a breach of the confidentiality provisions set forth in Section 10.14.

1.14Acknowledgement Regarding Any Supported QFCs.

(a)To the extent that the Loan Documents provide support, through a guarantee or otherwise, for Swap Agreements or any other agreement or instrument that is a QFC (such support “QFC Credit Support” and each such QFC a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Loan Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

(b)In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and such QFC Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Loan Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Loan Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support..

1.15Acknowledgement and Consent to Bail-In of Affected Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the Write-Down and Conversion Powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which

may be payable to it by any party hereto that is an Affected Financial Institution; and

(b)the effects of any Bail-In Action on any such liability, including, if applicable:

Section 60.a reduction in full or in part or cancellation of any such liability;

Section 61.a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

Section 62.the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of the applicable Resolution Authority.

[Remainder of page intentionally left blank. Signature pages follow.]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.

PACIFIC GAS AND ELECTRIC COMPANY
By:
	Name:
	Title:

JPMORGAN CHASE BANK, N.A. as Administrative Agent and as a Lender
By:
	Name:
	Title:

BANK OF AMERICA, N.A. as a Lender
By:
	Name:
	Title:

BARCLAYS BANK PLC as a Lender
By:
	Name:
	Title:

CITIBANK, N.A. as a Lender
By:
	Name:
	Title:

GOLDMAN SACHS BANK USA as a Lender
By:
	Name:
	Title:

BNP PARIBAS as a Lender
By:
	Name:
	Title:

By:
	Name:
	Title:

CREDIT SUISSE AG, NEW YORK BRANCH as a Lender
By:
	Name:
	Title:

By:
	Name:
	Title:

MIZUHO BANK, LTD. as a Lender
By:
	Name:
	Title:

MUFG UNION BANK, N.A. as a Lender
By:
	Name:
	Title:

WELLS FARGO BANK, NATIONAL ASSOCIATION as a Lender
By:
	Name:
	Title:

BANK OF MONTREAL, CHICAGO BRANCH as a Lender
By:
	Name:
	Title:

THE BANK OF NEW YORK MELLON as a Lender
By:
	Name:
	Title:

BANK OF CHINA, LOS ANGELES BRANCH as a Lender
By:
	Name:
	Title:

EX-10.30

Exhibit 10.30

AMENDMENT NO. 3 TO CREDIT AGREEMENT

This AMENDMENT NO. 3, dated as of February 8, 2022 (this “Amendment”), is entered into by and among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), the Consenting Lenders (as defined below), and JPMORGAN CHASE BANK, N.A. (“JPMCB”), as administrative agent (in such capacity and including any successors in such capacity, the “Administrative Agent”).

RECITALS:

WHEREAS, reference is hereby made to the Term Loan Credit Agreement, dated as of July 1, 2020, among the Borrower, the lenders party thereto from time to time, the Administrative Agent and the other parties thereto (as amended by that certain Amendment No. 1 to Credit Agreement dated as of October 29, 2021 (the “Amendment No. 1”) and that certain Amendment No. 2 to Credit Agreement dated as of December 31, 2021 (the “Amendment No. 2”), the “Credit Agreement”, capitalized terms used (including in the preamble and recitals hereto) but not defined herein shall have the meanings assigned to such terms in the Credit Agreement (as amended hereby));

WHEREAS, the Borrower, the Lenders party thereto and the Administrative Agent previously entered into the Amendment No. 1 pursuant to which the Lenders party thereto agreed to extend the maturity date of the Loans held by such Lenders, which Loans are the 18-Month Tranche Loans (Tranche A);

WHEREAS, the Borrower, the Lenders party thereto and the Administrative Agent previously entered into the Amendment No. 2 pursuant to which the Lenders party thereto agreed to extend the maturity date of the Loans held by such Lenders, which Loans are the 18-Month Tranche Loans (Tranche B);

WHEREAS, as of the date hereof, the 18-Month Tranche Loans (Tranche A) and the 18-Month Tranche Loans (Tranche B) have the same maturity date;

WHEREAS, each Lender that executes and delivers an executed counterpart to this Amendment agrees to the terms of this Amendment upon the effectiveness of this Amendment on the Amendment No. 3 Effective Date (such Lenders, the “Consenting Lenders”), whereby the maturity date of the Loans held by such Consenting Lenders will be extended from October 1, 2022 to January 1, 2023 (the Loans so extended, the “Extended Loans”);

WHEREAS, the Loans that are not Extended Loans are being prepaid on the date of effectiveness of this Amendment (the “Prepayment”);

WHEREAS, the Consenting Lenders, constituting the Required Lenders and, after immediately giving effect to the Prepayment, constituting all the Lenders, agree to the other changes to the Credit Agreement set forth herein;

WHEREAS, JPMCB (or an Affiliate thereof) is acting as a joint lead arranger and bookrunner (in such capacity, the “Lead Arranger”) in respect of this Amendment; and

WHEREAS, this Amendment is an amendment made with the consent of all Lenders, the Borrower and the Administrative Agent pursuant to Section 10.1 of the Credit Agreement.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration (the receipt and sufficiency of which is hereby acknowledged), the parties hereto hereby agree as follows:

A.Amendments to Credit Agreement.

(i)Effective on the Amendment No. 3 Effective Date (as defined below) the Credit Agreement is hereby amended to:

(A)Amend Section 1.1 of the Credit Agreement by adding the following defined term in correct alphabetical order:

“Amendment No. 3 Effective Date”: February 8, 2022.

(B)Amending and restating the following defined terms contained in Section 1.1 of the Credit Agreement in their entirety as follows:

“18-Month Tranche Maturity Date”: January 1, 2023.

“Commitment”: as to any Lender, its 18-Month Tranche Commitment.

“Loans”: the 18-Month Tranche Loans.

“Maturity Date”: with respect to the 18-Month Tranche Loans, the 18-Month Tranche Maturity Date.

“Senior Bonds”: with respect to the 18-Month Tranche Loans, those certain First Mortgage Bonds in the aggregate combined initial principal amount of $1,500,000,000, in each case, issued to the Administrative Agent pursuant to the Supplemental Indenture.

“Tranche”: the 18-Month Tranche Commitments or the 18-Month Tranche Loans (or, with respect to the 18-Month Tranche Loans, the 18-Month Tranche Loans (Tranche A) and the 18-Month Tranche Loans (Tranche B)).

(C)Amend Section 1.1 of the Credit Agreement by deleting the following defined terms: “364-Day Tranche Commitment”, “364-Day Tranche Lender”, “364-Day Tranche Loans” and “364-Day Tranche Maturity Date”.

(D)Amend and restate Section 2.1(a) of the Credit Agreement in its entirety as follows:

“[Reserved].”

(E)Amend and restate Section 2.1(b) of the Credit Agreement in its entirety as follows:

(b)    Subject to the terms and conditions set forth herein, each 18-Month Tranche Lender (severally and not jointly) agrees to make a term loan (the “18-Month Tranche Loans”) to the Borrower in Dollars on the Effective Date in an aggregate amount equal to the amount of such 18-Month Tranche Lender’s 18-Month Tranche Commitment. Loans under the 18-Month Tranche may be ABR Loans or Term Benchmark Loans, as further provided herein. 18-Month Tranche Loans borrowed under this Section 2.1(b) and paid or prepaid may not be reborrowed. As of the Amendment No. 1 Effective Date, a portion of the 18-Month Tranche Loans in an aggregate amount of $1,315,735,897.44 (the “18-Month Tranche Loans (Tranche A)”) shall have an 18-Month Tranche Maturity Date of October 1, 2022 and a portion of the 18-Month Tranche Loans in an aggregate amount of $184,264,102.56 (the “18-Month Tranche Loans (Tranche B)”) shall have an 18-Month Tranche Maturity Date of January 1, 2022. As of the Amendment No. 2 Effective Date, the 18-Month Tranche Loans (Tranche B) shall have an 18-Month Tranche Maturity Date of October 1, 2022. As of the Amendment No. 3 Effective Date, all 18-Month Tranche Loans shall have an 18-Month Tranche Maturity Date of January 1, 2023.

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(F)Amend Section 2.6 of the Credit Agreement by amending and restating clause (c) thereof as follows:

(c)    On April 1, 2022, the Borrower agrees to pay to the Administrative Agent, for the account of each Lender that holds any 18-Month Tranche Loans outstanding on such date, a fee equal to 0.075% of the principal amount of such Loans.

(G)Amend Section 2.6 of the Credit Agreement by deleting clause (d) thereof.

(H)Amend and restate Section 2.14(b) of the Credit Agreement in its entirety as follows:

(b)     Each payment (including each prepayment) by the Borrower on account of principal of and interest on the Loans shall be made pro rata in the case of the 18-Month Tranche Loans, according to the respective outstanding principal amounts of the 18-Month Tranche Loans then held by the 18-Month Tranche Lenders.

(ii)Effective on February 18, 2022, which is the last day of the Interest Period in effect immediately prior to the Amendment No. 3 Effective Date for the outstanding Loans, the Credit Agreement is hereby amended to delete the stricken text (indicated textually in the same manner as the following example: stricken text) and to add the double-underlined text (indicated textually in the same manner as the following example: double-underlined text) as set forth in the pages of the Credit Agreement attached as Exhibit A hereto.

(iii)Notwithstanding anything to the contrary in Section 2.14(b) or any other provision of the Credit Agreement, the Consenting Lenders hereby consent to the Prepayment on the Amendment No. 3 Effective Date without the ratable repayment of the Extended Loans (and interest thereon) on such date.

B.Allocations of Loans. On the Amendment No. 3 Effective Date, after giving effect to the Prepayment, the allocation of the 18-Month Tranche Loans are as set forth as Schedule 1.1 hereto.

C.Conditions Precedent. This Amendment shall become effective as of the date first above written when, and only when, each of the following conditions precedent shall have been satisfied or, to the extent permitted under the Credit Agreement, waived (the “Amendment No. 3 Effective Date”):

1.Executed Counterparts. The Administrative Agent shall have received a counterpart to this Amendment duly executed by the Borrower, the Consenting Lenders, the Required Lenders and the Administrative Agent.

2.Organizational Documents; Certificates. The Administrative Agent shall have received (i) a certificate of the Borrower, dated the Amendment No. 3 Effective Date (with a recent short-form good standing certificate of the Borrower), similar to the one delivered pursuant to Section 5.1(f) of the Credit Agreement, with appropriate insertions and attachments and (ii) a certificate of a Responsible Officer, dated the Amendment No. 3 Effective Date, confirming the satisfaction of the conditions precedent set forth in clauses (3) and (4) below.

3.Representations and Warranties. The representations and warranties of the Borrower contained in Section 4 of the Credit Agreement (other than the representations and warranties set forth in Sections 4.2, 4.6(b) and 4.13)shall be true and correct in all material respects immediately prior to and immediately after giving effect to this Amendment; provided that each of such representations and warranties that contains a materiality qualification shall be true and correct on and as of the Amendment No. 3 Effective Date (or, to the extent such representations and warranties specifically relate to an earlier date, such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date).

4.No Default. No Default or Event of Default shall have occurred and be continuing immediately prior to, and immediately after giving effect to, the Amendment No. 3 Effective Date.

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5.Fees and Expenses. On or prior to the Amendment No. 3 Effective Date, the Borrower shall have paid all reasonable out-of-pocket costs and expenses of the Administrative Agent and the Lead Arrangers required to be paid or reimbursed by the Borrower in connection with the preparation, negotiation, execution and delivery of this Amendment and related documentation (including, in each case, without limitation, the reasonable fees and disbursements of counsel for the Administrative Agent and the Lead Arrangers with respect thereto).

6.KYC Information. At least three (3) Business Days prior to the Amendment No. 3 Effective Date, the Administrative Agent and each Consenting Lender shall have received all documentation and information relating to the Borrower as is reasonably requested in writing by the Administrative Agent and/or any such Consenting Lender at least ten (10) Business Days prior to the Amendment No. 3 Effective Date that is required by Governmental Authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation. If the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation and the Administrative Agent or any Consenting Lender so request at least five (5) Business Days prior to the Amendment No. 3 Effective Date, then at least three (3) Business Days prior to the Amendment No. 3 Effective Date, the Borrower shall have delivered to the Administrative Agent and/or any such Consenting Lender a Beneficial Ownership Certification in relation to the Borrower.

7.Bond Documents. The Administrative Agent shall have received evidence reasonably satisfactory to it that the Borrower has caused to be delivered to the Trustee under the FMB Indenture the items described in Section IV Extension Procedures for the Bonds of the Thirty-Fourth Series of the Eleventh Supplemental Indenture.

D.Other Terms.

1.Reference to the Effect on the Loan Documents.

(i)As of the Amendment No. 3 Effective Date, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, and each reference in the other Loan Documents to the “Credit Agreement” (including, without limitation, by means of words like “thereunder,” “thereof” and words of like import), shall mean and be a reference to the Credit Agreement as amended hereby, and this Amendment and the Credit Agreement shall be read together and construed as a single instrument.

(ii)Except as expressly amended hereby or specifically waived or consented to above, all of the terms and provisions of the Credit Agreement and all other Loan Documents are and shall remain in full force and effect and are hereby ratified and confirmed.

(iii)The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders, the Borrower, the Lead Arrangers or the Administrative Agent under any of the Loan Documents, nor constitute a waiver or amendment of any other provision of any of the Loan Documents or for any purpose except as expressly set forth herein.

(iv)This Amendment is a Loan Document.

2.Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page of (x) this Amendment and/or (y) any document, amendment, approval, consent, information, notice, certificate, request, statement, disclosure or authorization related to this Amendment and/or the transactions contemplated hereby (each an “Ancillary Document”) that is an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record (each, an “Electronic Signature”) transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually

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executed counterpart of this Amendment or such Ancillary Document, as applicable. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Amendment and/or any Ancillary Document shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be.

3.Ratification. This Amendment shall be effective pursuant to Section 10.1 of the Credit Agreement (and approved and ratified by the Consenting Lenders, the Required Lenders and the Administrative Agent for all purposes under the Loan Documents).

4.Governing Law.THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

5.Section Titles. The section titles contained in this Amendment are and shall be without substantive meaning or content of any kind whatsoever and are not a part of the agreement between the parties hereto, except when used to reference a section.

6.Notices. All communications and notices hereunder shall be given as provided in the Credit Agreement.

7.Severability. The fact that any term or provision of this Amendment is held invalid, illegal or unenforceable as to any person in any situation in any jurisdiction shall not affect the validity, enforceability or legality of the remaining terms or provisions hereof or the validity, enforceability or legality of such offending term or provision in any other situation or jurisdiction or as applied to any person.

8.Successors. The terms of this Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns.

9.Jurisdiction; Waiver of Jury Trial. The jurisdiction and waiver of right to trial by jury provisions in Section 10.12 and Section 10.15, respectively, of the Credit Agreement are incorporated herein by reference mutatis mutandis.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, each of the undersigned has caused its duly authorized officer to execute and deliver this Amendment as of the date first set forth above.

PACIFIC GAS AND ELECTRIC COMPANY,
as the Borrower

By:    /s/ Margaret K. Becker                           

Name: Margaret K. Becker

Title: Vice President and Treasurer

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

JPMORGAN CHASE BANK, N.A., as Administrative Agent
By:	/s/ Arina Mavilian
Name:    Arina Mavilian
Title: Executive Director

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WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Consenting Lender
By:	/s/ Gregory R. Gredvig
Name:    Gregory R. Gredvig
Title:    Director

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

BARCLAYS BANK PLC, as a Consenting Lender
By:	/s/ Sam Yoo
Name:    Sam Yoo
Title:    Managing Director

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

MIZUHO BANK, LTD., as a Consenting Lender
By:	/s/ Edward Sacks
Name:    Edward Sacks
Title:    Authorized Signatory

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

GOLDMAN SACHS BANK USA, as a Consenting Lender
By:	/s/ Thomas Manning
Name:    Thomas Manning
Title:    Authorized Signatory

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

CITIBANK, N.A., as a Consenting Lender
By:	/s/ Richard Rivera
Name:    Richard Rivera
Title:    Vice President

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

BANK OF AMERICA, N.A., as a Consenting Lender
By:	/s/ Dee Dee Farkas
Name:    Dee Dee Farkas
Title:    Managing Director

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

BNP PARIBAS, as a Consenting Lender
By:	/s/ Denis O’Meara
Name:    Denis O’Meara
Title:    Managing Director
By:	/s/ Victor Padilla
Name:    Victor Padilla
Title:    Vice President

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

BANK OF MONTREAL, CHICAGO BRANCH, as a Consenting Lender
By:	/s/ Darren Thomas
Name:    Darren Thomas
Title:    Director

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

MUFG UNION BANK, N.A., as a Consenting Lender
By:	/s/ Nietzsche Rodricks
Name:    Nietzsche Rodricks
Title:    Managing Director

Signature Page to Amendment No. 3
Pacific Gas and Electric Company

Execution Version

EXHIBIT A

Attached.

$3,000,000,000

TERM LOAN CREDIT AGREEMENT

among

PACIFIC GAS AND ELECTRIC COMPANY,
as Borrower,

the Several Lenders from Time to Time Parties Hereto,

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent,

BOFA SECURITIES, INC.,

BARCLAYS BANK PLC,

CITIBANK, N.A.,

and GOLDMAN SACHS BANK USA,
as Co-Syndication Agents,

and

BNP PARIBAS,

CREDIT SUISSE AG, NEW YORK BRANCH,

MIZUHO BANK, LTD.,

MUFG UNION BANK, N.A.,

and WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Co-Documentation Agents

Dated as of July 1, 2020

as amended by Amendment No. 23 to Credit Agreement dated as of December 31, 2021February 8, 2022

JPMorgan Chase Bank, N.A.,
BofA Securities, Inc.,
Barclays Bank PLC,
Citibank, N.A.
and Goldman Sachs Bank USA
as Joint Lead Arrangers and
Joint Bookrunners

13

TABLE OF CONTENTS

Page

SECTION 1.DEFINITIONS    1

1.1Defined Terms    1

1.2Other Definitional Provisions and Interpretative Provisions    30

1.3Divisions    31

1.4Interest Rates; LIBORBenchmark Notification    31

SECTION 2.AMOUNT AND TERMS OF THE TERM LOANS    32

2.1Loans    32

2.2Procedures for Borrowing3233

2.3[Reserved]    33

2.4[Reserved]    33

2.5[Reserved]    33

2.6Fees, Etc.    33

2.7Termination of Commitments    33

2.8Prepayments3334

2.9Conversion and Continuation Options3435

2.10Limitations on EurodollarTerm Benchmark Tranches    35

2.11Interest Rates and Payment Dates    35

2.12Computation of Interest and Fees    36

2.13Inability to Determine Interest Rate    36

2.14Pro Rata Treatment and Payments; Notes3839

2.15Change of Law3941

2.16Taxes4142

2.17Indemnity4546

2.18Change of Lending Office4547

2.19Replacement of Lenders4647

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2.20Defaulting Lenders4647

2.21[Reserved]49

SECTION 3.[RESERVED].4749

SECTION 4.REPRESENTATIONS AND WARRANTIES4749

4.1Financial Condition4749

4.2No Change4849

4.3Existence; Compliance with Law4849

4.4Power; Authorization; Enforceable Obligations4850

4.5No Legal Bar4950

4.6Litigation4950

4.7No Default4951

4.8Taxes4951

4.9Federal Regulations5051

4.10ERISA5051

4.11Investment Company Act; Other Regulations5052

4.12Use of Proceeds5152

4.13Environmental Matters5152

4.14Regulatory Matters5152

4.15Sanctions; Anti-Corruption5152

4.16Affected Financial Institutions5153

4.17Solvency5153

4.18Disclosure5153

4.19Status of Obligations5253

4.20Ownership of Property5253

4.21Covered Entity53

SECTION 5.CONDITIONS PRECEDENT5254

5.1Conditions to the Effective Date5254

ii

SECTION 6.AFFIRMATIVE COVENANTS5456

6.1Financial Statements5456

6.2Certificates; Other Information5556

6.3Payment of Taxes.5657

6.4Maintenance of Existence; Compliance5657

6.5Maintenance of Property; Insurance5658

6.6Inspection of Property; Books and Records; Discussions5658

6.7Notices5758

6.8Maintenance of Licenses, etc.5759

6.9Further Assurances5759

6.10Use of Proceeds59

SECTION 7.NEGATIVE COVENANTS5859

7.1Indebtedness5859

7.2Consolidated Capitalization Ratio6061

7.3Liens6061

7.4Fundamental Changes6061

7.5Sale and Lease Back Transactions6062

7.6Swap Agreements6162

7.7Amendments to FMB Indenture6162

SECTION 8.EVENTS OF DEFAULT6163

SECTION 9.THE AGENTS6465

9.1Appointment and Authority6465

9.2Delegation of Duties6466

9.3Exculpatory Provisions6466

9.4Reliance by Administrative Agent6567

9.5Notice of Default6667

9.6Non-Reliance on Agents and Other Lenders6668

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9.7Indemnification6668

9.8Agent in Its Individual Capacity6768

9.9Successor Agents6768

9.10Documentation Agents and Syndication Agents6870

9.11Administrative Agent May File Proofs of Claim6870

9.12Certain ERISA Matters6970

9.13Erroneous Payment6972

SECTION 10.MISCELLANEOUS7073

10.1Amendments and Waivers7073

10.2Notices7276

10.3No Waiver; Cumulative Remedies7477

10.4Survival of Representations and Warranties7478

10.5Payment of Expenses and Taxes7578

10.6Successors and Assigns; Participations and Assignments.7679

10.7Adjustments; Set off8083

10.8Counterparts; Electronic Execution; Binding Effect8184

10.9Severability8185

10.10Integration8285

10.11GOVERNING LAW8285

10.12Submission To Jurisdiction; Waivers8286

10.13Acknowledgments8386

10.14Confidentiality8387

10.15WAIVERS OF JURY TRIAL8487

10.16USA Patriot Act; Beneficial Ownership Regulation8487

10.17Judicial Reference8488

10.18No Advisory or Fiduciary Responsibility8488

10.19Acknowledgement Regarding Any Supported QFCs8588

iv

10.20Acknowledgement and Consent to Bail-In of Affected Financial Institutions8589

v

SCHEDULES:

1.1    Commitments

7.5    Sale and Lease Back Transactions

EXHIBITS:

A    [Reserved]

B    [Reserved]

C    Form of Compliance Certificate

D    Form of Closing Certificate

E    Form of Assignment and Assumption

F    [Reserved]

G    Forms of U.S. Tax Compliance Certificates

H    Form of Note

I    Form of Solvency Certificate

vi

This TERM LOAN CREDIT AGREEMENT (this “Agreement”), dated as of July 1, 2020, among PACIFIC GAS AND ELECTRIC COMPANY, a California corporation (the “Borrower”), the several banks and other financial institutions or entities from time to time parties to this Agreement (the “Lenders”) and JPMORGAN CHASE BANK, N.A., as administrative agent (in such capacity, together with any permitted successor thereto, the “Administrative Agent”).

W I T N E S S E T H:

WHEREAS, on January 29, 2019, the Borrower and PG&E Corporation, a California corporation and the holder of all of the issued and outstanding common stock of the Borrower (“PCG”) filed voluntary petitions for relief in the United States Bankruptcy Court for the Northern District of California (the “Bankruptcy Court”), and commenced their respective cases under chapter 11 of title 11 of the United States Code;

WHEREAS, on June 19, 2020, the Borrower and PCG filed the Debtors’ and Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization Dated June 19, 2020 [Docket No. 8048] (together with all exhibits, schedules, annexes, supplements, and other attachments thereto, and as may be further amended, modified or otherwise changed in accordance with this Agreement, the “Plan of Reorganization”);

WHEREAS, on June 20, 2020, the Plan of Reorganization was confirmed by the Bankruptcy Court and was consummated on the Effective Date;

WHEREAS, in connection with the foregoing, the Borrower has requested that the Lenders provide the term loans set forth herein and the Lenders are willing to make available to the Borrower such term loans upon the terms and subject to the conditions set forth herein; and

WHEREAS, in connection with and pursuant to Amendment No. 1, the Borrower has requested that this Agreement be amended as set forth in Amendment No. 1.

NOW, THEREFORE, IT IS AGREED AS FOLLOWS:

Section 1.DEFINITIONS

1.1Defined Terms. As used in this Agreement, the terms listed in this Section 1.1 shall have the respective meanings set forth in this Section 1.1.

“18-Month Tranche Commitment”: as to each 18-Month Tranche Lender, its obligation to make Loans under the 18-Month Tranche to the Borrower on the Effective Date pursuant to Section 2.1(b), in an aggregate principal amount equal to the amount set forth opposite such 18-Month Tranche Lender’s name on Schedule 1.1, as such amount may be adjusted from time to time in accordance with this Agreement. As of the Effective Date, the aggregate amount of the 18-Month Tranche Commitments for all 18-Month Tranche Lenders is $1,500,000,000.

“18-Month Tranche Lender”: a Lender with an 18-Month Tranche Commitment or holding 18-Month Tranche Loans.

“18-Month Tranche Loans”: as defined in Section 2.1(b).

“18-Month Tranche Loans(Tranche A)”: as defined in Section 2.1(b).

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“18-Month Tranche Loans(Tranche B)”: as defined in Section 2.1(b).

“18-Month Tranche Maturity Date”: (a) with respect to the 18-Month Tranche Loans (Tranche A), October 1, 2022 and (b) with respect to the 18-Month Tranche Loans (Tranche B), January 1, 20222023.

“364-Day Tranche Commitment”: as to each 364-Day Tranche Lender, its obligation to make Loans under the 364-Day Tranche to the Borrower on the Effective Date pursuant to Section 2.1(a), in an aggregate principal amount equal to the amount set forth opposite such 364-Day Tranche Lender’s name on Schedule 1.1, as such amount may be adjusted from time to time in accordance with this Agreement. As of the Effective Date, the aggregate amount of the 364-Day Tranche Commitments for all 364-Day Tranche Lenders is $1,500,000,000.

“364-Day Tranche Lender”: a Lender with a 364-Day Tranche Commitment or holding 364-Day Tranche Loans.

“364-Day Tranche Loans”: as defined in Section 2.1(a).

“364-Day Tranche Maturity Date”: the date that is 364 days after the Effective Date.

“ABR”: for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the NYFRB Rate in effect on such day plus ½ of 1% and (c) the EurodollarAdjusted Term SOFR Rate for a one month Interest Period commencing onas published two U.S. Government Securities Business Days prior to such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1%; provided that for the purpose of this definition, the EurodollarAdjusted Term SOFR Rate for any day shall be based on the Eurodollar Screen Rate (or if the Eurodollar Screen Rate is not available for such one month Interest Period, the Interpolated Rate)Term SOFR Reference Rate at approximately 11:00 a.m. London5:00 a.m. Chicago time on such day (or any amended publication time for the Term SOFR Reference Rate, as specified by the CME Term SOFR Administrator in the Term SOFR Reference Rate methodology). Any change in the ABR due to a change in the Prime Rate, the NYFRB Rate or the EurodollarAdjusted Term SOFR Rate shall be effective from and including the effective date of such change in the Prime Rate, the NYFRB Rate or the EurodollarAdjusted Term SOFR Rate, respectively. If ABR is being used as an alternate rate of interest pursuant to Section 2.13 (for the avoidance of doubt, only until any amendment has become effective pursuant to Section 2.13(b)), then ABR shall be the greater of clauses (a) and (b) above and shall be determined without reference to clause (c) above. If the ABR as determined pursuant to the foregoing would be less than 1.00%, such rate shall be deemed to be 1.00% for purposes of this Agreement.

“ABR Loans”: Loans the rate of interest applicable to which is based upon the ABR.

“Adjusted Daily Simple SOFR”: an interest rate per annum equal to (a) the Daily Simple SOFR, plus (b) 0.10%; provided that if the Adjusted Daily Simple SOFR Rate as so determined would be less than the Floor, such rate shall be deemed to be equal to the Floor for the purposes of this Agreement.

“Adjusted Term SOFR Rate”: for any Interest Period, an interest rate per annum equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10%; provided that if the Adjusted Term SOFR Rate as so determined would be less than the Floor,

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such rate shall be deemed to be equal to the Floor for the purposes of this Agreement.

“Administrative Agent”: as defined in the preamble hereto.

“Affected Financial Institution”: (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Affiliate”: with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“Agent Parties”: as defined in Section 10.2(d)(ii).

“Agents”: the collective reference to the Syndication Agents, the Documentation Agents, and the Administrative Agent.

“Agreement”: as defined in the preamble hereto.

“Amendment No. 1”: that certain Amendment No. 1 to Credit Agreement, dated as of the Amendment No. 1 Effective Date, among the Borrower, each Lender party thereto, and JPMorgan Chase Bank, N.A., as administrative agent.

“Amendment No. 1 Effective Date”: October 29, 2021.

“Amendment No. 2”: that certain Amendment No. 2 to Credit Agreement, dated as of the Amendment No. 2 Effective Date, among the Borrower, each Lender party thereto, and JPMorgan Chase Bank, N.A., as administrative agent.

“Amendment No. 2 Effective Date”: December 31, 2021.

“Amendment No. 3 Effective Date”: February 8, 2022.

“Anti-Corruption Laws”: as defined in Section 4.15.

“Applicable Margin”: for any day, (a) (i) with respect to any ABR Loans under the 364-Day Tranche, 1.00% per annum and (ii) with respect to Eurodollar Loans under the 364-Day Tranche, 2.00% per annum and (b) (i) with respect to any ABR Loans under the 18-Month Tranche, 1.25% per annum and (ii) with respect to EurodollarTerm Benchmark Loans under the 18-Month Tranche, 2.25% per annum.

“Approved Fund”: with respect to any Lender, any Person (other than a natural person) that is engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business that is administered or managed by (a) such Lender, (b) an Affiliate of such Lender or (c) an entity or an Affiliate of any entity that administers or manages such Lender.

“Arrangers”: the Joint Lead Arrangers and Joint Bookrunners identified on the cover hereto.

“A/R Securitization Assets”: (i) any accounts receivable, notes receivable, rights to future accounts receivable, notes receivable or residuals or other similar rights to payments due or any other rights to payment or related assets in respect of the provision of gas and electric service to consumers or otherwise (whether then existing or arising in

3

the future) of the Borrower or any of its Subsidiaries and the proceeds thereof and (ii) all collateral securing such receivable or asset, all contracts and contract rights, guarantees or other obligations in respect of such receivable or asset, lockbox accounts and records with respect to such receivables or asset and any other assets customarily transferred (or in respect of which security interests are customarily granted) together with receivables or assets in connection with a securitization transaction involving such assets.

“A/R Securitization Subsidiary”: PG&E AR Facility, LLC and any other Subsidiary formed and operating solely for the purpose of entering into A/R Securitization Transactions and engaging in activities ancillary thereto.

“A/R Securitization Transaction”: any financing transaction or series of financing transactions entered into by the Borrower or any Subsidiary of the Borrower pursuant to which the Borrower may sell, convey or otherwise transfer to any Person (including, without limitation, an A/R Securitization Subsidiary), or may grant a security interest in any A/R Securitization Assets and that are (other than to the extent of the Standard A/R Securitization Obligations) non-recourse to the Borrower or any of its Subsidiaries (other than an A/R Securitization Subsidiary).

“Assignee”: as defined in Section 10.6(b).

“Assignment and Assumption”: an Assignment and Assumption, substantially in the form of Exhibit E.

“Available Tenor”: as of any date of determination and with respect to the then-current Benchmark, as applicable, (x) if the then-current Benchmark is a term rate, any tenor for such Benchmark (or component thereof) or payment period for interest calculated with reference to such Benchmark (or component thereof), as applicable, that is or may be used for determining the length of an Interest Period or (y)for any term rate or otherwise, any payment period forfor determining any frequency of making payments of interest calculated with reference to such Benchmark, as applicable, pursuant to this Agreement as of such date and not including, for the avoidance of doubt, any tenor for such Benchmark that is then-removed from the definition of “Interest Period” pursuant to clause (e) of Section 2.13.

“Bail-In Action”: the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation”: (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation, rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Bankruptcy Court”: as defined in the first recital paragraph.

“Benchmark”: initially, the Eurodollar Basewith respect to any Term Benchmark Loan, the Term SOFR Rate; provided that if a replacement of the Benchmark has occurred pursuant to Section 2.13Benchmark Transition Event, and the related

4

Benchmark Replacement Date have occurred with respect to the Daily Simple SOFR or Term SOFR Rate, as applicable, or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate. Any reference to “Benchmark” shall include, as applicable, the published component used in the calculation thereofpursuant to clause (b) of Section 2.13.

“Benchmark Replacement”: for any Available Tenor:

(1) for purposes of Section 2.13(b), the first alternative set forth in the order below that can be determined by the Administrative Agent for the applicable Benchmark Replacement Date:

(1)the Adjusted Daily Simple SOFR; and

(a) the sum of: (i) Term SOFR and (ii) 0.11448% (11.448 basis points) for an Available Tenor of one-month’s duration, 0.26161% (26.161 basis points) for an Available Tenor of three-months’ duration, 0.42826% (42.826 basis points) for an Available Tenor of six-months’ duration and 0.71513% (71.513 basis points) for an Available Tenor of twelve-months’ duration; provided, that if any Available Tenor of the Eurodollar Base Rate does not correspond to an Available Tenor of Term SOFR, the Benchmark Replacement for such Available Tenor of the Eurodollar Base Rate shall be the closest corresponding Available Tenor (based on tenor) for Term SOFR, or and if such Available Tenor of the Eurodollar Base Rate corresponds equally to two Available Tenors of Term SOFR, the corresponding tenor of Term SOFR with the shorter duration shall be applied;

(b) the sum of: (i) Daily Simple SOFR and (ii) the spread adjustment selected or recommended by the Relevant Governmental Body for the replacement of the tenor of the Eurodollar Base Rate with a SOFR-based rate having approximately the same length as the interest payment period specified in clause (b) of Section 2.13 (which spread adjustment, for the avoidance of doubt, shall be 0.11448% (11.448 basis points); and

(2) for purposes of clause (c) of Section 2.13,     the sum of: (a) the alternate benchmark rate and (b) an adjustment (which may be a positive or negative value or zero), in each case, that has been selected by the Administrative Agent and the Borrower as the replacement for such Available Tenor of suchthe then-current Benchmark for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention, including any applicable recommendations made by the Relevant Governmental Body, for U.S.for determining a benchmark rate as a replacement for the then-current Benchmark for dollar-denominated syndicated credit facilities at such time in the United States and (b) the related Benchmark Replacement Adjustment;

provided that, ifIf the Benchmark Replacement as determined pursuant to clause (1) or (2) above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Loan Documents.

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“Benchmark Replacement Adjustment”: with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement for any applicable Interest Period and Available Tenor for any setting of such Unadjusted Benchmark Replacement, the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body as of the applicable Benchmark Replacement Date and/or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for dollar-denominated syndicated credit facilities at such time.

“Benchmark Replacement Conforming Changes”: with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “ABR,” the definition of “Business Day,” the definition of “U.S. Government Securities Business Day,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, the applicability and length of lookback periods, the applicability of breakage provisions, the formula for calculating any successor rates identified pursuant to the definition of “Benchmark Replacement” and other technical, administrative or operational matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of such Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Loan Documents), the formula, methodology or convention for applying the successor Floor to the successor Benchmark Replacement.

“Benchmark Replacement Date”: with respect to any Benchmark, the earliest to occur of the following events with respect to such then-current Benchmark:

(1)in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof); or

(2)in the case of clause (3) of the definition of “Benchmark Transition Event,” the first date on which such Benchmark (or the published component used in the calculation thereof) has been determined and announced by the regulatory supervisor for the administrator of such Benchmark (or such component thereof) to be no longer representative; provided, that such non-representativeness will be determined by reference to the most recent statement or publication referenced in such clause (c) and even if any Available Tenor of such Benchmark (or such component thereof) continues to be provided on such date.

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For the avoidance of doubt, (i) if the event giving rise to the Benchmark Replacement Date occurs on the same day as, but earlier than, the Reference Time in respect of any determination, the Benchmark Replacement Date will be deemed to have occurred prior to the Reference Time for such determination and (ii) the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Transition Event”: with respect to any then-current Benchmark other than the Eurodollar Base Rate, the occurrence of one or more of the following events: a public statement or publication of information by or on behalf of the administrator of thewith respect to such then-current Benchmark, :

(1) a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(2) a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Federal Reserve Board, the NYFRB, the CME Term SOFR Administrator, an insolvency official with jurisdiction over the administrator for such Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark, announcing or stating that (a) such(or such component), in each case, which states that the administrator of such Benchmark (or such component) has ceased or will cease on a specified date to provide all Available Tenors of such Benchmark,(or such component thereof) permanently or indefinitely,; provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark or (b) all Available Tenors of such Benchmark are or will no longer be representative of the underlying market and economic reality that such Benchmark is intended to measure and that representativeness will not be restored.(or such component thereof); or

(3) a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that all Available Tenors of such Benchmark (or such component thereof) are no longer, or as of a specified future date will no longer be, representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period”: with respect to any Benchmark, the period (if any) (x) beginning at the time that a Benchmark Replacement Date has occurred if,

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at such time, no Benchmark Replacement has replaced such then-current Benchmark for all purposes hereunder and under any Loan Document in accordance with Section 2.13 and (y) ending at the time that a Benchmark Replacement has replaced such then-current Benchmark for all purposes hereunder and under any Loan Document in accordance with Section 2.13.

“Beneficial Owner”: as defined in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Sections 13(d) and 14(d) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Beneficial Ownership Certification”: a certification regarding beneficial ownership or control as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation”: 31 C.F.R. § 1010.230.

“Benefit Plan”: any of (a) an “employee benefit plan” (as defined in ERISA) that is subject to Title I of ERISA, (b) a “plan” as defined in and subject to Section 4975 of the Code or (c) any Person whose assets include (for purposes of ERISA Section 3(42) or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.

“Benefitted Lender”: as defined in Section 10.7(a).

“BHC Act Affiliate”: an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)).

“Bond Delivery Agreement”: (i) that certain Bond Delivery Agreement, dated as of the Effective Date, between the Borrower and the Administrative Agent and (ii) that certain Bond Delivery Agreement, dated as of the Amendment No. 1 Effective Date, between the Borrower and the Administrative Agent.

“Bond Documents”: collectively, the FMB Indenture, the Supplemental Indenture, the Senior Bonds and the Bond Delivery Agreement.

“Borrower”: as defined in the preamble hereto.

“Bridge Facilities”: each of the bridge facilities outstanding, as of any date of determination, pursuant to the terms of the Utility Commitment Letter and the PCG Commitment Letter.

“Business Day”: a day (other than a Saturday,or a Sunday or other day) on which commercial banks are open for business in New York City or San Francisco, California are authorized or required by law to close, provided, that with respect to notices and determinations in connection with, and payments of principal and interest on, Eurodollar Loans, such day is also a day for trading by and between banks in Dollar deposits in the London interbank eurodollar market.Chicago; provided that, in relation to RFR Loans and any interest rate settings, fundings, disbursements, settlements or payments of any such RFR Loan, or any other dealings of such RFR Loan, any such day that is only an U.S. Government Securities Business Day.

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“Capital Lease Obligations”: as to any Person, the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on the balance sheet of such Person under GAAP and, for the purposes of this Agreement, the amount of such obligations at any time shall be the capitalized amount thereof at such time determined in accordance with GAAP, subject to Section 1.2(f).

“Capital Stock”: any and all shares, interests, participations or other equivalents (however designated) of capital stock of a corporation, any and all equivalent ownership interests in a Person (other than a corporation) and any and all warrants, rights or options to purchase any of the foregoing.

“Cash Management Agreement”: any agreement to establish or maintain accounts or provide cash management services, including treasury, depository, overdraft, netting services, cash pooling arrangements, credit or debit card, purchasing card, electronic funds transfer, automated clearing house, foreign exchange facilities and other cash management arrangements.

“Change of Control”: the occurrence of one of the following:

Section 2.(A) PCG shall at any time not be the Beneficial Owner of 100% of the common stock of the Borrower or (B) PCG shall at any time not be the Beneficial Owner of at least 70% of the voting Capital Stock of the Borrower; or

Section 3.any person or group (within the meaning of the Exchange Act and the rules of the SEC thereunder as of the Effective Date) shall become the Beneficial Owner of shares representing more than 35% of the voting power of the Capital Stock of PCG; or

Section 4.at any point during any period of 24 consecutive months, commencing after the Effective Date, individuals who at the beginning of such 24-month period were directors of PCG, together with any directors whose election or nomination for election to the board of directors of PCG (whether by the board of directors of PCG or any shareholder of PCG) was approved by a majority of the directors who either were directors of PCG at the beginning of such 24-month period or whose election or nomination for election was so approved, cease to constitute a majority of the board of directors of PCG (it being understood and agreed that, for the avoidance of doubt, the change of directors of PCG contemplated by the Plan of Reorganization shall not constitute a Change of Control); or

Section 5.there shall have been (A) [reserved] or (B) a transfer of the license and/or operating assets constituting more than 10% of the Net Tangible Assets of the Borrower to the State of California, to any other Governmental Authority or to a third party at the direction of State of California, the CPUC or any similar Governmental Authority.

“Change of Law”: the occurrence, after the Effective Date, of any of the following: (a) the adoption or taking effect of any law, rule, regulation, statute, treaty, policy, guideline or directive by any Governmental Authority, (b) any change in any law, rule, regulation, statute, treaty, policy, guideline or directive or in the application, interpretation, promulgation, implementation, administration or enforcement thereof by any Governmental Authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall

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Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change of Law”, regardless of the date enacted, adopted or issued.

“CME Term SOFR Administrator”: CME Group Benchmark Administration Limited as administrator of the term Secured Overnight Financing Rate (SOFR) (or a successor administrator; provided that, in the event there are multiple successor administrators, the successor administrator hereunder shall be selected by the Administrative Agent and the Borrower).

“Code”: the Internal Revenue Code of 1986, as amended from time to time.

“Commitment”: as to any Lender, its 364-Day Tranche Commitment or 18-Month Tranche Commitment.

“Commitment Letter”: that certain Term Loan Commitment Letter dated as of May 26, 2020 among Pacific Gas and Electric Company, as the borrower, PG&E Corporation and the commitment parties from time to time party thereto, as amended, modified or supplemented from time to time prior to the date hereof.

“Commonly Controlled Entity”: an entity, whether or not incorporated, that is under common control with the Borrower within the meaning of Section 4001 of ERISA or is part of a group that includes the Borrower and that is treated as a single employer under Section 414 of the Code.

“Communications”: as defined in Section 10.2(d)(ii).

“Compliance Certificate”: a certificate duly executed by a Responsible Officer substantially in the form of Exhibit C.

“Conduit Lender”: any special purpose corporation organized and administered by any Lender for the purpose of making Loans otherwise required to be made by such Lender and designated by such Lender in a written instrument; provided, that the designation by any Lender of a Conduit Lender shall not relieve the designating Lender of any of its obligations to fund a Loan under this Agreement if, for any reason, its Conduit Lender fails to fund any such Loan, and the designating Lender (and not the Conduit Lender) shall have the sole right and responsibility to deliver all consents and waivers required or requested under this Agreement with respect to its Conduit Lender, and provided, further, that no Conduit Lender shall (a) be entitled to receive any greater amount pursuant to Sections 2.15, 2.16, 2.17 or 10.5 than the designating Lender would have been entitled to receive in respect of the extensions of credit made by such Conduit Lender or (b) be deemed to have any Commitment.

“Connection Income Taxes”: Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Consolidated Capitalization”: on any date of determination, the sum of (a) Consolidated Total Debt on such date, plus without duplication, (b) (i) the amounts set forth opposite the captions “common shareholders’ equity” (or any similar caption) and

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“preferred stock” (or any similar caption) on the consolidated balance sheet, prepared in accordance with GAAP, of the Borrower and its Subsidiaries as of such date, and (ii) the outstanding principal amount of any junior subordinated deferrable interest debentures or other similar securities issued by the Borrower or any of its Subsidiaries after the Effective Date.

“Consolidated Capitalization Ratio”: on any date of determination, the ratio of (a) Consolidated Total Debt to (b) Consolidated Capitalization.

“Consolidated Total Debt”: at any date, the aggregate principal amount of all obligations of the Borrower and its Significant Subsidiaries at such date that in accordance with GAAP would be classified as debt on a consolidated balance sheet of the Borrower, and without duplication all Guarantee Obligations of the Borrower and its Significant Subsidiaries at such date in respect of obligations of any other Person that in accordance with GAAP would be classified as debt on a consolidated balance sheet of such Person; provided that, the determination of “Consolidated Total Debt” shall exclude, without duplication, (a) the Securitized Bonds and any Indebtedness under any A/R Securitization Transaction, (b) Indebtedness of the Borrower and its Significant Subsidiaries in an amount equal to the amount of cash held as cash collateral for any fully cash collateralized letter of credit issued for the account of the Borrower or any Significant Subsidiary, (c) imputed Indebtedness of the Borrower or any Significant Subsidiary incurred in connection with power purchase and fuel agreements, (d) any junior subordinated deferrable interest debenture or other similar securities issued by the Borrower and (e) as of any date of determination, the amount of any securities included within the caption “preferred stock” (or any similar caption) on a consolidated balance sheet, prepared in accordance with GAAP, of the Borrower as of such date.

“Contractual Obligation”: as to any Person, any provision of any security issued by such Person or of any agreement, instrument or other undertaking to which such Person is a party or by which it or any of its property is bound.

“Control”: the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. “Controlling” and “Controlled” have meanings correlative thereto.

“Corresponding Tenor”: with respect to any Available Tenor means, as applicable, either a tenor (including overnight) or an interest payment period having approximately the same length (disregarding business day adjustment) as such Available Tenor.

“Covered Entity”: any of the following:

(i)a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b);

Section 6.a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or

Section 7.a “covered FSI” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).

“Covered Party”: as defined in Section 10.19.

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“CPUC”: the California Public Utilities Commission or its successor.

“Daily Simple SOFR”: for any day, (a “SOFR, with the conventions for this rate (which will include a lookback) being established by the Administrative Agent in accordance with the conventions for this rate recommended by the Relevant Governmental Body for determining “Daily Simple SOFR” for syndicated business loans; provided, that if the Administrative Agent decides that any such convention is not administratively feasible for the Administrative Agent, then the Administrative Agent may establish another convention in its reasonable discretion.Rate Day”), a rate per annum equal to SOFR for the day (such day “SOFR Determination Date”) that is five (5) U.S. Government Securities Business Day prior to (i) if such SOFR Rate Day is a U.S. Government Securities Business Day, such SOFR Rate Day or (ii) if such SOFR Rate Day is not a U.S. Government Securities Business Day, the U.S. Government Securities Business Day immediately preceding such SOFR Rate Day, in each case, as such SOFR is published by the SOFR Administrator on the SOFR Administrator’s Website. Any change in Daily Simple SOFR due to a change in SOFR shall be effective from and including the effective date of such change in SOFR without notice to the Borrower.

“Debt Issuance”: the issuance of Securitized Bonds under or pursuant to the Application of Pacific Gas and Electric Company for (1) Administration of Stress Test Methodology Developed Pursuant to Public Utilities Code Section 451.2(b) and (2) Determination That $7.5 Billion of 2017 Catastrophic Wildfire Costs and Expenses Are Stress Test Costs That May Be Financed Through Issuance of Recovery Bonds Pursuant to Section 451.2(c) and Section 850 et seq. (U39E) - Application No. 20-04-023 dated as of April 30, 2020, or the contemplated subsequent and related application for the issuance of a financing order authorizing the securitization transaction described in A.20-04-023, to be filed later in 2020 and consolidated therewith, by the Borrower or any of its Subsidiaries.

“Debtor Relief Laws”: the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect.

“Default”: any of the events specified in Section 8, whether or not any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

“Default Right”: the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

“Defaulting Lender”: subject to the penultimate paragraph of Section 2.20, any Lender, as reasonably determined by the Administrative Agent, that has (a) failed to fund any portion of its Loans within two (2) Business Days of the date required to be funded by it under this Agreement, unless such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable Default, shall be specifically identified in such writing) has not been satisfied, (b) notified the Borrower, the Administrative Agent or any other Lender in writing that it does not intend to comply with any of its funding obligations under this Agreement or has made a public statement to the effect that it does not intend to comply with its funding obligations under this Agreement (other than a notice of a good faith dispute or related communications) or generally under other agreements in which it commits to

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extend credit, unless such writing or public statement relates to such Lender’s obligation to fund a Loan hereunder and states that such position is based on such Lender’s good faith determination that a condition precedent to funding (which condition precedent, together with any applicable Default, shall be specifically identified in such writing or public statement) cannot be satisfied, (c) failed, within two (2) Business Days after written request by the Administrative Agent or the Borrower, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund prospective Loans, unless the subject of a good faith dispute (provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent or the Borrower), (d) otherwise failed to pay over to the Administrative Agent or any other Lender any other amount required to be paid by it under this Agreement within two (2) Business Days of the date when due, unless the subject of a good faith dispute, or (e) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had a custodian appointed for it, or has consented to, approved of or acquiesced in any such proceeding or appointment or has a parent company that has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it, or has consented to, approved of or acquiesced in any such proceeding or appointment, or (iii) become the subject of a Bail-In Action; provided that (x) if a Lender would be a “Defaulting Lender” solely by reason of events relating to a parent company of such Lender or solely because a Governmental Authority has been appointed as receiver, conservator, trustee or custodian for such Lender, in each case as described in clause (e) above, the Administrative Agent may, in its discretion, determine that such Lender is not a “Defaulting Lender” if and for so long as the Administrative Agent is satisfied that such Lender will continue to perform its funding obligations hereunder and (y) a Lender shall not be a Defaulting Lender solely by virtue of the ownership or acquisition of voting stock or any other Capital Stock in such Lender or a parent company thereof by a Governmental Authority or an instrumentality thereof, or the exercise of control over such Lender or parent company thereof, by a Governmental Authority or instrumentality thereof so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (a) through (e) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to the penultimate paragraph of Section 2.20) upon delivery of written notice of such determination to the Borrower and each Lender.

“Disposition”: with respect to any property, any sale, lease, sale and leaseback, assignment, conveyance, transfer or other disposition thereof. The term “Dispose of” shall have a correlative meaning.

“Documentation Agents”: as defined on the cover hereto.

“Dollars” and “$”: dollars in lawful currency of the United States.

“Early Opt-in Effective Date”: with respect to any Early Opt-in Election, the sixth (6th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, so long as the Administrative Agent has not received, by 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, written notice of objection to such Early Opt-in Election from Lenders comprising the Required Lenders.

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“Early Opt-in Election”: the occurrence of the following:

(1)a notification by the Administrative Agent to (or the request by the Borrower to the Administrative Agent to notify) each of the other parties hereto that at least five currently outstanding U.S. dollar-denominated syndicated credit facilities in the U.S. syndicated loan market at such time contain (as a result of amendment or as originally executed) a SOFR-based rate (including SOFR, a term SOFR or any other rate based upon SOFR) as a benchmark rate (and such syndicated credit facilities are identified in such notice and are publicly available for review); and

(2)the joint election by the Administrative Agent and the Borrower to trigger a fallback from Eurodollar Base Rate and the provision by the Administrative Agent of written notice of such election to the Lenders.

“EEA Financial Institution”: (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country”: any of the member states of the European Union, Iceland, Liechtenstein and Norway.

“EEA Resolution Authority”: any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Effective Date”: the date on which the conditions precedent set forth in Section 5.1 shall have been satisfied or waived, which date is July 1, 2020.

“Eligible Assignee”: (a) any commercial bank or other financial institution having a senior unsecured debt rating by Moody’s of A3 or better and by S&P of A- or better, which is domiciled in a country which is a member of the OECD or (b) with respect to any Person referred to in the preceding clause (a), any other Person that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of business all of the Capital Stock of which is owned, directly or indirectly, by such Person; provided that in the case of clause (b), the Administrative Agent shall have consented to the designation of such Person as an Eligible Assignee (such consent not to be unreasonably withheld or delayed).

“Environmental Laws”: any and all foreign, Federal, state, local or municipal laws, rules, orders, regulations, statutes, ordinances, codes, decrees, requirements of any Governmental Authority or other Requirements of Law (including common law) regulating, relating to or imposing liability or standards of conduct concerning protection of human health or the environment, as now or may at any time hereafter be in effect.

“ERISA”: the Employee Retirement Income Security Act of 1974, as amended from time to time.

“ERISA Event”: (a) any Reportable Event; (b) the failure of the Borrower or any Commonly Controlled Entity to timely make a required contribution with respect to any

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Plan or any Multiemployer Plan; (c) the imposition of a Lien under Section 430 of the Code or Section 303 of ERISA with respect to any Single Employer Plan; (d) the failure of the Borrower or any Commonly Controlled Entity to meet the minimum funding standard under Section 412 or 430 of the Code with respect to any Plan or the filing of an application for a funding waiver with respect to any Single Employer Plan; (e) the incurrence by the Borrower or any Commonly Controlled Entity of any liability under Title IV of ERISA, including with respect to the termination of any Plan (other than the payment of PBGC premiums in the ordinary course); (f) (i) the termination of, or the filing or receipt of a notice of intent to terminate, a Single Employer Plan under Section 4041 of ERISA, or the treatment of a plan amendment as a termination under Section 4041 of ERISA, or (ii) (A) the appointment of a trustee to administer a Single Employer Plan under Section 4042, or (B) the institution by the PBGC of proceedings to terminate a Single Employer Plan or to have a trustee appointed to administer a Single Employer Plan, or receipt by the Borrower of notice from the PBGC thereof, where such proceedings continue unstayed or in effect for more than 60 days, or such notice is not withdrawn by the PBGC within 60 days following delivery by PBGC; (g) the incurrence by the Borrower or any Commonly Controlled Entity of any liability with respect to the complete withdrawal or partial withdrawal under Title IV of ERISA from any Multiemployer Plan; (h) the receipt by the Borrower or any Commonly Controlled Entity of any notice from a Multiemployer Plan concerning the imposition of Withdrawal Liability; (i) receipt of notification by Borrower or any Commonly Controlled Entity from a Multiemployer Plan that such Multiemployer Plan is in endangered or critical status (within the meaning of Section 305 of ERISA) or in Insolvency; (j) the incurrence by the Borrower or any Commonly Controlled Entity of any liability pursuant to Section 4063 or 4064 of ERISA or a substantial cessation of operations with respect to a Plan within the meaning of Section 4062(e) of ERISA; (k) the posting of a bond or security under Section 436(f) of the Code with respect to any Plan; or (l) the Borrower incurs material tax liability with respect to any Plan (including Sections 4975, 4980B, 4980D, 4980H and 4980I of the Code, as applicable).

“Erroneous Payment”: as defined in Section 9.13(a).

“EU Bail-In Legislation Schedule”: the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Eurocurrency Liabilities”: as defined in Regulation D of the Federal Reserve Board.

“Eurocurrency Reserve Requirements”: of any Lender for any Interest Period as applied to a Eurodollar Loan, the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during any such percentage shall be so applicable) under any regulations of the Federal Reserve Board or other Governmental Authority having jurisdiction with respect to determining the maximum reserve requirement (including basic, supplemental and emergency reserves) for such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period.

“Eurodollar Base Rate”: with respect to each day during each Interest Period pertaining to a Eurodollar Loan, the Eurodollar Screen Rate at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period; provided that if the Eurodollar Screen Rate shall not be available at such time for such Interest Period (an “Impacted Interest Period”) then the Eurodollar Base Rate shall be the Interpolated Rate.

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“Eurodollar Loans”: Loans the rate of interest applicable to which is based upon the Eurodollar Rate.

“Eurodollar Rate”: with respect to each day during each Interest Period pertaining to a Eurodollar Loan, a rate per annum determined for such day in accordance with the following formula (rounded upwards, if necessary, to the next 1/16 of 1%):

Eurodollar Base Rate

1.00 - Eurocurrency Reserve Requirements

“Eurodollar Screen Rate”: for any day and time, with respect to any Eurodollar Loan for any Interest Period, the London interbank offered rate as administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate) for a period equal in length to such Interest Period as displayed on such day and time on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate (or, in the event such rate does not appear on a Reuters page or screen, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion); provided that if the Eurodollar Screen Rate as so determined would be less than zero, such rate shall be deemed to zero for the purposes of this Agreement.

“Eurodollar Tranche”: the collective reference to Eurodollar Loans the then current Interest Periods with respect to all of which begin on the same date and end on the same later date (whether or not such Loans shall originally have been made on the same day).

“Event of Default”: any of the events specified in Section 8, provided that any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

“Exchange Act”: Securities Exchange Act of 1934, as amended.

“Excluded Taxes”: any of the following Taxes imposed on or with respect to any Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan (other than pursuant to an assignment request by the Borrower under Section 2.19) or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 2.16(a) or (c), amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such Recipient’s failure to

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comply with Section 2.16(e) and (d) any U.S. federal withholding Taxes imposed pursuant to FATCA.

“FATCA”: Sections 1471 through 1474 of the Code, as of the Effective Date (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreements entered into pursuant to Section 1471(b)(1) of the Code.

“FCA”: as defined in Section 2.13(b).

“FCPA”: as defined in Section 4.15.

“Federal Funds Effective Rate”: for any day, the rate calculated by the NYFRB based on such day’s federal funds transactions by depositary institutions, as determined in such manner as shall be set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as the effective federal funds rate; provided that if the Federal Funds Effective Rate as so determined would be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

“Federal Reserve Board”: the Board of Governors of the Federal Reserve System of the United States of America.

“First Mortgage Bonds”: bonds issued by the Borrower pursuant to the FMB Indenture.

“Floor”: the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to Eurodollar Base Rate.the Adjusted Term SOFR Rate. For the avoidance of doubt the initial Floor for each of the Adjusted Term SOFR Rate or the Adjusted Daily Simple SOFR shall be 0.0%.

“FMB Indenture”: the Indenture of Mortgage (Mortgage), dated as of June 19, 2020, between the Borrower and the Indenture Trustee (as supplemented by the Supplemental Indenture) and as further supplemented or amended from time to time.

“Foreign Lender”: a Lender that is not a U.S. Person.

“FPA”: the Federal Power Act, as amended, and the rules and regulations promulgated thereunder.

“Funding Office”: the office of the Administrative Agent specified in Section 10.2(a) or such other office as may be specified from time to time by the Administrative Agent as its funding office by written notice to the Borrower and the Lenders.

“GAAP”: generally accepted accounting principles in the United States as in effect from time to time, except as noted below. In the event that any “Change in Accounting Principles” (as defined below) shall occur and such change results in a change in the method of calculation of financial covenants, standards or terms in this Agreement, then, upon the request of the Borrower or the Required Lenders, the Borrower and the Administrative Agent agree to enter into negotiations in order to amend such provisions of this Agreement so as to reflect equitably such Change in Accounting Principles with the desired result that the criteria for evaluating the Borrower’s financial condition shall be the same after such Change in Accounting Principles as if such Change in Accounting Principles had not been made. Until such time as such an amendment shall have been executed and delivered by the Borrower, the Administrative Agent and the Required

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Lenders, all financial covenants, standards and terms in this Agreement shall continue to be calculated or construed as if such Change in Accounting Principles had not occurred. “Change in Accounting Principles” refers to (i) changes in accounting principles required by the promulgation of any rule, regulation, pronouncement or opinion by the Financial Accounting Standards Board of the American Institute of Certified Public Accountants or any successor thereto, the SEC or, if applicable, the Public Company Accounting Oversight Board and (ii) any change in the application of GAAP concurred by the Borrower’s independent public accountants and disclosed in writing to the Administrative Agent.

“Governmental Authority”: any nation or government, any state or other political subdivision thereof, any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative functions of or pertaining to government, any securities exchange and any self-regulatory organization (including the National Association of Insurance Commissioners and supra-national bodies such as the European Union or the European Central Bank).

“Guarantee Obligation”: as to any Person (the “guaranteeing person”), any obligation, including a reimbursement, counterindemnity or similar obligation, of the guaranteeing person that guarantees any Indebtedness, leases, dividends or other obligations (the “primary obligations”) of any other third Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of the guaranteeing person, whether or not contingent, (i) to purchase any such primary obligation or any property constituting direct or indirect security therefor, (ii) to advance or supply funds (1) for the purchase or payment of any such primary obligation or (2) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (iii) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation, (iv) otherwise to assure or hold harmless the owner of any such primary obligation against loss in respect thereof or (v) to reimburse or indemnify an issuer of a letter of credit, surety bond or guarantee issued by such issuer in respect of primary obligations of a primary obligor other than the Borrower or any Significant Subsidiary; provided, however, that the term Guarantee Obligation shall not include endorsements of instruments for deposit or collection in the ordinary course of business. The amount of any Guarantee Obligation of any guaranteeing person shall be deemed to be the lower of (a) an amount equal to the stated or determinable amount of the primary obligation in respect of which such Guarantee Obligation is made and (b) the maximum amount for which such guaranteeing person may be liable pursuant to the terms of the instrument embodying such Guarantee Obligation, unless such primary obligation and the maximum amount for which such guaranteeing person may be liable are not stated or determinable, in which case the amount of such Guarantee Obligation shall be such guaranteeing person’s reasonably anticipated liability in respect thereof as determined by the Borrower in good faith.

“IBA”: as defined in Section 2.13(b).

“Indebtedness”: of any Person at any date, without duplication, (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person for the deferred purchase price of property or services (other than trade payables, including under energy procurement and transportation contracts, incurred in the ordinary course of such Person’s business), (c) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (d) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by

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such Person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), (e) all Capital Lease Obligations of such Person, (f) all obligations of such Person, contingent or otherwise, as an account party or applicant under or in respect of acceptances, letters of credit, surety bonds or similar arrangements (other than reimbursement obligations, which are not due and payable on such date, in respect of documentary letters of credit issued to provide for the payment of goods and services in the ordinary course of business), (g) the liquidation value of all mandatorily redeemable preferred Capital Stock of such Person, (h) all Guarantee Obligations of such Person in respect of obligations of the kind referred to in clauses (a) through (g) above, (i) all obligations of the kind referred to in clauses (a) through (h) above secured by (or for which the holder of such obligation has an existing right, contingent or otherwise, to be secured by) any Lien on property (including accounts and contract rights) owned by such Person, whether or not such Person has assumed or become liable for the payment of such obligation (provided, that if such Person is not liable for such obligation, the amount of such Person’s Indebtedness with respect thereto shall be deemed to be the lesser of the stated amount of such obligation and the value of the property subject to such Lien), and (j) for the purposes of Sections 7.1 and 8(e) only, all obligations of such Person in respect of Swap Agreements, provided that Indebtedness as used in this Agreement shall exclude any Non-Recourse Debt and any obligations under any A/R Securitization Transaction. The Indebtedness of any Person shall include the Indebtedness of any other entity (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person’s ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness expressly provide that such Person is not liable therefor.

“Indebtedness Covenant Release Date”: the date of the expiration of the temporary waiver from its authorized capital structure granted by the CPUC on May 28, 2020.

“Indemnified Liabilities”: as defined in Section 10.5.

“Indemnified Taxes”: (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.

“Indemnitee”: as defined in Section 10.5.

“Indenture Trustee”: The Bank of New York Mellon Trust Company, N.A. and any successor thereto as trustee under the FMB Indenture.

“Insolvency”: with respect to any Multiemployer Plan, the condition that such plan is insolvent within the meaning of Section 4245 of ERISA.

“Interest Payment Date”: (a) as to any ABR Loan, the last day of each March, June, September and December to occur while such Loan is outstanding and the final maturity date of such Loan, (b) as to any Eurodollar Loan having an Interest Period of three months or less,with respect to any RFR Loan, each date that is on the numerically corresponding day in each calendar month that is one month after the Borrowing of such Loan (or, if there is no such numerically corresponding day in such month, then the last day of such Interest Period, (c) as to any Eurodollar Loan having an Interest Period longer than three months, each day that is three months, or a whole multiple thereof, after the first day of such Interest Period andmonth), (c) with respect to any Term Benchmark Loan, the last day of sucheach Interest Period

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applicable to the Borrowing of which such Loan is a part and (d) as to any Loan, the date of any repayment or prepayment made in respect thereof.

“Interest Period”: as to any EurodollarTerm Benchmark Loan, (a) initially, the period commencing on the borrowing or conversion date, as the case may be, with respect to such EurodollarTerm Benchmark Loan and ending one weekmonth thereafter or one, three or six or (if agreed to by all Lenders) twelve months thereafter, as selected by the Borrower in its notice of borrowing or notice of conversion, as the case may be, given with respect thereto; and (b) thereafter, each period commencing on the last day of the next preceding Interest Period applicable to such EurodollarTerm Benchmark Loan and ending one, three or six or (if agreed to by all Lenders) twelve months thereafter, as selected by the Borrower by irrevocable notice to the Administrative Agent not later than 12:00 Noon, New York City time, on the date that is three Business Days prior to the last day of the then current Interest Period with respect theretomonth thereafter ; provided that, all of the foregoing provisions relating to Interest Periods are subject to the following:

(i)if any Interest Period would otherwise end on a day that is not a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless the result of such extension would be to carry such Interest Period into another calendar month in which event such Interest Period shall end on the immediately preceding Business Day;

Section 8.the Borrower may not select an Interest Period that would extend beyond the applicable Maturity Date;

Section 9.any Interest Period that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of a calendar month;

Section 10.[reserved]; and

Section 11.at the election of the Borrower, the initial Interest Period for any EurodollarTerm Benchmark Loans made on the Effective Date, shall commence on the Effective Date and end on the last day of the calendar month during which the Effective Date occurs; and.

(vi) the option to elect a one week Interest Period shall only be available during the calendar year ending December 31, 2021 and solely to the extent such Interest Period is available to the Administrative Agent.

“Interpolated Rate”: at any time, for any Interest Period, the rate per annum (rounded to the same number of decimal places as the Eurodollar Screen Rate) determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the Eurodollar Screen Rate for the longest period (for which the Eurodollar Screen Rate is available) that is shorter than the Impacted Interest Period; and (b) the Eurodollar Screen Rate for the shortest period (for which that Eurodollar Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“IRS”: the United States Internal Revenue Service.

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“knowledge of the Borrower”: actual knowledge of any Responsible Officer of the Borrower.

“Laws”: collectively, all international, foreign, federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, requests, licenses, authorizations and permits of, and agreements with, any Governmental Authority, in each case whether or not having the force of law.

“Lenders”: as defined in the preamble hereto, including each Lender set forth under the heading “Lender” on Schedule I of Amendment No. 1 and their respective successors and assigns as permitted hereunder; provided, that unless the context otherwise requires, each reference herein to the Lenders shall be deemed to include any Conduit Lender.

“LIBOR”: as defined in Section 1.4.

“Lien”: any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge or other security interest or any preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever (including any conditional sale or other title retention agreement and any Capital Lease Obligation having substantially the same economic effect as any of the foregoing).

“Loans”: the 364-Day Tranche Loans and the 18-Month Tranche Loans.

“Loan Documents”: this Agreement, the Notes, the Supplemental Indenture, the Senior Bonds, the Bond Delivery Agreement, the FMB Indenture and, in each case, any amendment, waiver, supplement or other modification to any of the foregoing; provided, that the term “Loan Documents” shall not include the FMB Indenture for any purposes under Section 2.16, Section 8 or Section 10 (other than for the purposes of Sections 10.1(iv) 10.1(x)).

“Material Adverse Effect”: (a) a change in the business, property, operations or financial condition of the Borrower and its Subsidiaries taken as a whole that could reasonably be expected to materially and adversely affect the Borrower’s ability to perform its obligations under the Loan Documents or (b) a material adverse effect on (i) the validity or enforceability of this Agreement or any of the other Loan Documents or (ii) the rights and remedies of the Administrative Agent and the Lenders, taken as a whole, under this Agreement or any other Loan Document.

“Materials of Environmental Concern”: any gasoline or petroleum (including crude oil or any fraction thereof) or petroleum products or any hazardous or toxic substances, materials or wastes, defined or regulated as such in or under any Environmental Law, including asbestos, polychlorinated biphenyls and urea-formaldehyde insulation.

“Maturity Date”: (a) with respect to the 364-Day Tranche Loans, the 364-Day Tranche Maturity Date, and (b) with respect to the 18-Month Tranche Loans, the 18-Month Tranche Maturity Date.

“Moody’s”: Moody’s Investors Service, Inc.

“Mortgaged Property”: as defined in the FMB Indenture.

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“Multiemployer Plan”: a plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Net Cash Proceeds”: with respect to any Debt Issuance, the excess, if any, of (i) cash actually received by the Borrower or its Subsidiaries in connection with such incurrence, issuance, offering or placement over (ii) the underwriting discounts and commissions and other fees and expenses incurred by the Borrower or its Subsidiaries in connection with such incurrence, issuance, offering or placement.

“Net Tangible Assets”: the total amount of the Borrower’s assets determined on a consolidated basis in accordance with GAAP as of the last day of the most recently ended fiscal quarter for which financial statements have been delivered under Section 6.1, less (a) the sum of the Borrower’s consolidated current liabilities determined in accordance with GAAP, and (b) the amount of the Borrower’s consolidated assets classified as intangible assets, determined in accordance with GAAP.

“Non-Recourse Debt”: Indebtedness of the Borrower or any of its Significant Subsidiaries that is incurred in connection with the acquisition, construction, sale, transfer or other Disposition of specific assets, to the extent recourse, whether contractual or as a matter of law, for non-payment of such Indebtedness is limited (a) to such assets, or (b) if such assets are (or are to be) held by a Subsidiary formed solely for such purpose, to such Subsidiary or the Capital Stock of such Subsidiary.

“Notes”: as defined in Section 2.14(f).

“NYFRB”: the Federal Reserve Bank of New York.

“NYFRB Rate”: for any day, the greater of (a) the Federal Funds Effective Rate in effect on such day and (b) the Overnight Bank Funding Rate in effect on such day (or for any day that is not a Business Day, for the immediately preceding Business Day); provided that if none of such rates are published for any day that is a Business Day, the term “NYFRB Rate” means the rate for a federal funds transaction quoted at 11:00 a.m. (New York City time) on such day received by the Administrative Agent from a federal funds broker of recognized standing selected by it; provided, further, that if any of the aforesaid rates as so determined would be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“NYFRB’s Website”: the website of the NYFRB at http://www.newyorkfed.org, or any successor source.

“Obligations”: the unpaid principal of and interest on (including, without limitation, interest accruing after the maturity of the Loans and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to the Borrower, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) the Loans and all other obligations and liabilities of the Borrower to the Administrative Agent or to any Lender, whether direct or indirect, absolute or contingent, due or to become due, or now existing or hereafter incurred, which may arise under, out of, or in connection with, this Agreement, any other Loan Document or any other document made, delivered or given in connection herewith or therewith, whether on account of principal, interest, reimbursement obligations, fees, indemnities, costs, expenses (including, without limitation, all fees, charges and disbursements of counsel to the Administrative Agent or to any Lender that are required to be paid by the Borrower pursuant hereto) or otherwise.

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“OECD”: the countries constituting the “Contracting Parties” to the Convention on the Organisation For Economic Co-operation and Development, as such term is defined in Article 4 of such Convention.

“Other Connection Taxes”: with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Other Taxes”: all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 2.19).

“Overnight Bank Funding Rate”: for any day, the rate comprised of both overnight federal funds and overnight Eurodollar borrowings by U.S.-managed banking offices of depository institutions, as such composite rate shall be determined by the NYFRB as set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as an overnight bank funding rate.

“Participant”: as defined in Section 10.6(c).

“Participant Register”: as defined in Section 10.6(c)(iii).

“Patriot Act”: as defined in Section 10.16.

“Payment Recipient”: as defined in Section 9.13(a).

“PBGC”: the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA (or any successor).

“PCG”: as defined in the first recital paragraph.

“PCG Commitment Letter”: that certain Commitment Letter dated as of October 4, 2019 among PG&E Corporation, as the borrower, Pacific Gas and Electric Company and the commitment parties from time to time party thereto, as amended, modified or supplemented from time to time prior to the date hereof.

“PCG Revolving Credit Agreement”: that certain Credit Agreement dated as of the Effective Date, among PCG, the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent.

“Percentage”: as to any Lender at any time with respect to a Tranche, the percentage which the aggregate principal amount of such Lender’s Loans then outstanding constitutes of the aggregate principal amount of the Loans then outstanding with respect to such Tranche.

“Permitted Refinancing”: with respect to any Indebtedness (the “Refinanced Indebtedness”), any extension, refinancing, refunding or replacement thereof with

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Indebtedness provided that (i) the amount of such Indebtedness does not exceed the aggregate principal amount of the Refinanced Indebtedness, plus any premium, interest, fee or expenses payable in connection therewith, (ii) the final maturity date of such Indebtedness is no earlier than the maturity date of the Refinanced Indebtedness, and (iii) the weighted average life to maturity of such Indebtedness is not shorter than the weighted average life to maturity of the Refinanced Indebtedness.

“Person”: an individual, partnership, corporation, limited liability company, business trust, joint stock company, trust, unincorporated association, joint venture, Governmental Authority or other entity of whatever nature.

“Plan”: at a particular time, any employee benefit plan that is covered by ERISA and in respect of which the Borrower or a Commonly Controlled Entity is (or, if such plan were terminated at such time, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

“Plan of Reorganization”: as defined in the second recital paragraph.

“Platform”: as defined in Section 10.2(d).

“Prime Rate”: the rate of interest last quoted by The Wall Street Journal as the “Prime Rate” in the U.S. or, if The Wall Street Journal ceases to quote such rate, the highest per annum interest rate published by the Federal Reserve Board in Federal Reserve Statistical Release H.15 (519) (Selected Interest Rates) as the “bank prime loan” rate or, if such rate is no longer quoted therein, any similar rate quoted therein (as determined by the Administrative Agent) or in any similar release by the Federal Reserve Board (as determined by the Administrative Agent). Each change in the Prime Rate shall be effective from and including the date such change is publicly announced or quoted as being effective.

“PTE”: a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“QFC”: the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

“QFC Credit Support” in Section 10.19.

“Qualified Securitization Bond Issuer”: a Subsidiary of the Borrower formed and operating solely for the purpose of (a) purchasing and owning property created under a “financing order” (as such term is defined in the California Public Utilities Code) or similar order issued by the CPUC, (b) issuing such securities pursuant to such order, (c) pledging its interests in such property to secure such securities and (d) engaging in activities ancillary to those described in (a), (b) and (c).

“Rating”: each rating announced by S&P and Moody’s in respect of the Borrower’s senior secured debt.

“Recipient”: the Administrative Agent or any Lender.

“Reference Time”: with respect to any setting of the then-current Benchmark means (1) if such Benchmark is the Term SOFR Rate, 5:00 a.m. (Chicago time) on the day that is two Business Days preceding the date of such setting, (2) if such Benchmark is Daily Simple SOFR, then four Business Days prior to such setting or

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(3) if such Benchmark is none of the Term SOFR Rate or Daily Simple SOFR, the time determined by the Administrative Agent in its reasonable discretion.

“Register”: as defined in Section 10.6(b).

“Regulation U”: Regulation U of the Federal Reserve Board as in effect from time to time.

“Related Parties”: with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

“Relevant Governmental Body”: the Federal Reserve Board and/or the NYFRB, the CME Term SOFR Administrator, as applicable, or a committee officially endorsed or convened by the Federal Reserve Board and/or the NYFRB or, in each case, any successor thereto.

“Relevant Rate”: (i) with respect to any Term Benchmark Borrowing, the Adjusted Term SOFR Rate or (ii) with respect to any RFR Borrowing, the Adjusted Daily Simple SOFR, as applicable.

“Removal Effective Date”: as defined in Section 9.9(b).

“Reportable Event”: any of the events set forth in Section 4043(c) of ERISA, other than those events as to which the thirty-day notice period is waived under subsections .27, .28, .29, .30, .31, .32, .34 or .35 of PBGC Reg. § 4043.

“Required Lenders”: at any time, the holders of more than 50% of the aggregate Loans then outstanding. The Loans of any Defaulting Lender shall be disregarded in determining Required Lenders at any time.

“Requirement of Law”: as to any Person, the Articles of Incorporation and By-Laws or other organizational or governing documents of such Person, and any law, treaty, rule or regulation or determination of an arbitrator or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject.

“Resignation Effective Date”: as defined in Section 9.9(a).

“Resolution Authority”: with respect to any EEA Financial Institution, an EEA Resolution Authority and, with respect to any UK Financial Institution, a UK Resolution Authority.

“Responsible Officer”: the chief executive officer, president, chief financial officer, treasurer or assistant treasurer of the Borrower, but in any event, with respect to financial matters, the chief financial officer, treasurer or assistant treasurer of the Borrower.

“RFR Borrowing”: as to any Borrowing, the RFR Loans comprising such Borrowing.

“RFR Loan”: a Loan that bears interest at a rate based on the Adjusted Daily Simple SOFR.

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“S&P”: Standard & Poor’s Global Ratings, a division of S&P Global Inc., and any successor thereto.

“Sanctions”: as defined in Section 4.15.

“SEC”: the Securities and Exchange Commission, any successor thereto and any analogous Governmental Authority.

“Securitized Bonds”: without duplication, securities, however denominated, that are (i) issued by a Qualified Securitization Bond Issuer, (ii) secured by or otherwise payable from charges authorized by the financing order referred to in clause (a) of the definition of “Qualified Securitization Bond Issuer,” and (iii) non-recourse to the Borrower or any of its Subsidiaries (other than the issuer of such securities).

“Senior Bonds”: (i) with respect to the 364-Day Tranche Loans, that certain First Mortgage Bond in the aggregate principal amount of $1,500,000,000 and (ii) with respect to the 18-Month Tranche Loans, those certain First Mortgage Bonds in the aggregate combined initial principal amount of $1,500,000,000, in each case, issued to the Administrative Agent pursuant to the Supplemental Indenture.

“Significant Subsidiary”: as defined in Article 1, Rule 1-02(w) of Regulation S-X of the Exchange Act as of the Effective Date, provided that notwithstanding the foregoing, no special purpose finance subsidiary, no A/R Securitization Subsidiary (or Subsidiaries of any A/R Securitization Subsidiary) nor any Qualified Securitization Bond Issuer (or Subsidiaries of any Qualified Securitization Bond Issuer) shall constitute a Significant Subsidiary. Unless otherwise qualified, all references to a “Significant Subsidiary” or to “Significant Subsidiaries” in this Agreement shall refer to a “Significant Subsidiary” or “Significant Subsidiaries” of the Borrower.

“Single Employer Plan”: any Plan that is covered by Title IV of ERISA, but that is not a Multiemployer Plan.

“SOFR”: a rate equal to the secured overnight financing rate as administered by the SOFR Administrator.

“SOFR Administrator”: the NYFRB (or a successor administrator of the secured overnight financing rate).

“SOFR”: a rate per annum equal to the secured overnight financing rate for such Business Day published by the NYFRB (or a successor administrator of the secured overnight financing rate) on the NYFRB’s Website (Administrator’s Website”: the NYFRB’s website, currently at http://www.newyorkfed.org, or any successor source for the secured overnight financing rate identified as such by the administrator of the secured overnight financing rateSOFR Administrator from time to time).

“SOFR Determination Date”: has the meaning specified in the definition of “Daily Simple SOFR”.

“SOFR Rate Day”: has the meaning specified in the definition of “Daily Simple SOFR”.

“Solvent”: with respect to the Borrower and its Subsidiaries, on a consolidated basis, that as of the date of determination, (i) the fair value of the assets of the Borrower and its Subsidiaries, on a consolidated basis, at a fair valuation on a going concern basis,

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exceeds, on a consolidated basis, their debts and liabilities, subordinated, contingent or otherwise, (ii) the present fair saleable value of the property of the Borrower and its Subsidiaries, on a consolidated and going concern basis, is greater than the amount that will be required to pay the probable liability, on a consolidated basis, of their debts and other liabilities, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured in the ordinary course of business, (iii) the Borrower and its Subsidiaries, on a consolidated basis, are able to pay their debts and liabilities, subordinated, contingent or otherwise, as such liabilities become absolute and matured in the ordinary course of business, (iv) the Borrower and its Subsidiaries are not engaged in businesses, and are not about to engage in businesses for which they have unreasonably small capital. For purposes of this definition, the amount of any contingent liability at any time shall be computed as the amount that, in light of all the facts and circumstances existing as of the Effective Date, would reasonably be expected to become an actual and matured liability.

“Specified Exchange Act Filings”: the Borrower’s Form 10-K annual report for the year ended December 31, 2020 and each and all of the Form 10-Qs and Form 8-Ks (and to the extent applicable proxy statements) filed by the Borrower or PCG with the SEC after December 31, 2020 and prior to the date that is one Business Day before the Amendment No. 1 Effective Date.

“Specified Material Adverse Effect”: any occurrence, fact, change, event, effect, violation, penalty, inaccuracy or circumstance that, individually or in the aggregate with any such other results, occurrences, facts, changes, events, effects, violations, penalties, inaccuracies, or circumstances, (i) would have or would reasonably be expected to have a material adverse effect on the business, operations, assets, liabilities, capitalization, financial performance, financial condition or results of operations, in each case, of PCG and the Borrower, taken as a whole, or (ii) would reasonably be expected to prevent or materially delay the ability of the Borrower to consummate the transactions contemplated by this Agreement or perform its obligations hereunder; provided, however, that none of the following results, occurrences, facts, changes, events, effects, violations, penalties, inaccuracies or circumstances shall constitute or be taken into account in determining whether a Specified Material Adverse Effect has occurred, is continuing or would reasonably be expected to occur: (A) [reserved], (B) results, occurrences, facts, changes, events, violations, inaccuracies or circumstances affecting (1) the electric or gas utility businesses in the United States generally or (2) the economy, credit, financial, capital or commodity markets, in the United States or elsewhere in the world, including changes in interest rates, monetary policy or inflation, (C) changes or prospective changes in law (other than any law or regulation of California or the United States that is applicable to any electrical utility) or in GAAP or accounting standards, or any changes or prospective changes in the interpretation or enforcement of any of the foregoing, (D) any decline in the market price, or change in trading volume, of any securities of PCG, (E) any failure to meet any internal or public projections, forecasts, guidance, estimates, milestones, credit ratings, budgets or internal or published financial or operating predictions of revenue, earnings, cash flow or cash position, (F) [reserved], and (G) one or more wildfires, occurring on or after January 1, 2020, that destroys or damages fewer than 500 dwellings or commercial structures in the aggregate (it being understood that (I) the exceptions in clauses (D) and (E) shall not prevent or otherwise affect a determination that the underlying cause of any such change, decline or failure referred to therein is a Specified Material Adverse Effect, and (II) a Specified Material Adverse Effect shall include the occurrence of one or more wildfires on or after January 1, 2020 destroying or damaging at least 500 dwellings or commercial structures within PCG’s service area at a time when the portion of PCG’s system at the location of such wildfire was not successfully de-energized).

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“Standard A/R Securitization Obligations”: representations, warranties, covenants, indemnities, repurchase obligations, servicing obligations, guarantees, intercompany notes and obligations relating to contributions of A/R Securitization Assets to an A/R Securitization Subsidiary and other obligations entered into by the Borrower or any of its Subsidiaries which are reasonably customary in A/R Securitization Transactions.

“Subsidiary”: as to any Person, a corporation, partnership, limited liability company or other entity of which shares of stock or other ownership interests having ordinary voting power (other than stock or such other ownership interests having such power only by reason of the happening of a contingency) to elect a majority of the board of directors or other managers of such corporation, partnership or other entity are at the time owned, or the management of which is otherwise controlled, directly or indirectly through one or more intermediaries, or both, by such Person. Unless otherwise qualified, all references to a “Subsidiary” or to “Subsidiaries” in this Agreement shall refer to a Subsidiary or Subsidiaries of the Borrower.

“Supplemental Indenture”: with respect to those certain First Mortgage Bonds in the aggregate principal amount of $3,000,000,000 issued to the Administrative Agent, the Supplemental Indenture, dated as of the Effective Date, by and between the Borrower and the Indenture Trustee.

“Supported QFC”: as defined in Section 10.19.

“Swap Agreement”: any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or any of its Subsidiaries shall be a “Swap Agreement”.

“Syndication Agents”: as defined on the cover hereto.

“Taxes”: all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Term Benchmark”: when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted Term SOFR Rate.

“Term SOFR”: for the applicable corresponding tenor, the forward-looking term rate based on SOFR that has been selected or recommended by the Relevant Governmental Body.Determination Day”: has the meaning assigned to it under the definition of Term SOFR Rate.

“Term SOFR Rate”: with respect to any Term Benchmark Borrowing and for any tenor comparable to the applicable Interest Period, the Term SOFR Reference Rate at approximately 5:00 a.m., Chicago time, two U.S. Government Securities Business Days prior to the commencement of such tenor comparable to the applicable Interest Period (such day, the “Term SOFR Determination Day”), as such rate is published by the CME Term SOFR Administrator.

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“Term SOFR Reference Rate”: for any day and time, with respect to any Term Benchmark Borrowing denominated in Dollars and for any tenor comparable to the applicable Interest Period, the rate per annum determined by the Administrative Agent as the forward-looking term rate based on SOFR. If by 5:00 pm (New York City time) on the Term SOFR Determination Day, the “Term SOFR Reference Rate” for the applicable tenor has not been published by the CME Term SOFR Administrator and a Benchmark Replacement Date with respect to the Term SOFR Rate has not occurred, then the Term SOFR Reference Rate for such Term SOFR Determination Day will be the Term SOFR Reference Rate as published in respect of the first preceding U.S. Government Securities Business Day for which such Term SOFR Reference Rate was published by the CME Term SOFR Administrator, so long as such first preceding Business Day is not more than five (5) Business Days prior to such Term SOFR Determination Day.

“Tranche”: (i) the 364-Day Tranche Commitments or the 364-Day Tranche Loans or (ii) the 18-Month Tranche Commitments or the 18-Month Tranche Loans (or, with respect to the 18-Month Tranche Loans, the 18-Month Tranche Loans (Tranche A) and the 18-Month Tranche Loans (Tranche B)).

“Transferee”: any Assignee or Participant.

“Type”: as to any Loan, its nature as an ABR Loan or a EurodollarTerm Benchmark Loan.

“UK Financial Institution”: any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority)) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority”: the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“Unadjusted Benchmark Replacement”: the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

“United States” or “U.S.”: the United States of America.

“U.S. Government Securities Business Day”: any day except for (i) a Saturday, (ii) a Sunday or (iii) a day on which the Securities Industry and Financial Markets Association recommends that the fixed income departments of its members be closed for the entire day for purposes of trading in United States government securities.

“U.S. Person”: any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Code.

“U.S. Special Resolution Regime”: as defined in Section 10.19.

“U.S. Tax Compliance Certificate”: as defined in Section 2.16(e)(ii)(B)(III).

“Utility Commitment Letter”: that certain Commitment Letter dated as of October 4, 2019 among Pacific Gas and Electric Company, as the borrower, PG&E Corporation and

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the commitment parties from time to time party thereto, as amended, modified or supplemented from time to time prior to the date hereof.

“Utility Revolving Credit Agreement”: that certain Credit Agreement dated as of the Effective Date, among the Borrower, the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent.

“Withdrawal Liability”: any liability to a Multiemployer Plan as a result of a complete or partial withdrawal by the Borrower or any Commonly Controlled Entity from such Multiemployer Plan, as such terms are defined in Title IV of ERISA.

“Write-Down and Conversion Powers”: (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the applicable Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to any UK Resolution Authority, any powers of such UK Resolution Authority under the applicable Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

1.1Other Definitional Provisions and Interpretative Provisions.

(a)Unless otherwise specified therein, all terms defined in this Agreement shall have the defined meanings when used in the other Loan Documents or any certificate or other document made or delivered pursuant hereto or thereto.

(b)As used herein and, except as otherwise provided therein, in the other Loan Documents, and any certificate or other document made or delivered pursuant hereto or thereto, (i) accounting terms relating to the Borrower and its Significant Subsidiaries defined in Section 1.1 and accounting terms partly defined in Section 1.1, to the extent not defined, shall have the respective meanings given to them under GAAP, (ii) the words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”, (iii) the word “incur” shall be construed to mean incur, create, issue, assume or become liable in respect of (and the words “incurred” and “incurrence” shall have correlative meanings), (iv) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, Capital Stock, securities, revenues, accounts, leasehold interests and contract rights, and (v) references to agreements or other Contractual Obligations shall, unless otherwise specified, be deemed to refer to such agreements or Contractual Obligations as amended, supplemented, restated or otherwise modified from time to time.

(c)The words “hereof”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section,

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Schedule and Exhibit references are to this Agreement unless otherwise specified.

(d)The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

(e)The Borrower shall not be required to perform, nor shall it be required to guarantee the performance of, any of the affirmative covenants set forth in Section 6 that apply to any of its Significant Subsidiaries nor shall any of the Borrower’s Significant Subsidiaries be required to perform, nor shall any of such Significant Subsidiaries be required to guarantee the performance of, any of the Borrower’s affirmative covenants set forth in Section 6 or any of the affirmative covenants set forth in Section 6 that apply to any other Significant Subsidiary; provided, that nothing in this Section 1.2(e) shall prevent the occurrence of a Default or an Event of Default arising out of the Borrower’s failure to cause any Significant Subsidiary to comply with the provisions of this Agreement applicable to such Significant Subsidiary.

(f)Notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to any change in accounting for leases pursuant to GAAP resulting from the implementation of Financial Accounting Standards Board ASU No. 2016-02, Leases (Topic 842), to the extent such adoption would require treating any lease (or similar arrangement conveying the right to use) as a capital lease where such lease (or similar arrangement) would not have been required to be so treated under GAAP as in effect on December 31, 2015.

1.2Divisions. For all purposes under the Loan Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized and acquired on the first date of its existence by the holders of its Capital Stock at such time.

1.3Interest Rates; LIBORBenchmark Notification. The interest rate on Eurodollar Loans is determined by reference to the Eurodollar Base Rate, which is derived from the London interbank offered rate (“LIBOR”). LIBOR is intended to represent the rate at which contributing banks may obtain short-term borrowings from each other in the London interbank market. On March 5, 2021, the FCA publicly announced that: (a) immediately after December 31, 2021, publication of all seven euro LIBOR settings, all seven Swiss Franc LIBOR settings, the spot next, 1-week, 2-month and 12-month Japanese Yen LIBOR settings, the overnight, 1-week, 2-month and 12-month British Pound Sterling LIBOR settings, and the 1-week and 2-month U.S. Dollar LIBOR settings will permanently cease; immediately after June 30, 2023, publication of the overnight and 12-month U.S. Dollar LIBOR settings will permanently cease; immediately after December 31, 2021, the 1-month, 3-month and 6-month Japanese Yen LIBOR settings and the 1-month, 3-month and 6-month British Pound Sterling LIBOR settings will cease to be provided or, subject to consultation

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by the FCA, be provided on a changed methodology (or “synthetic”) basis and no longer be representative of the underlying market and economic reality they are intended to measure and that representativeness will not be restored; and immediately after June 30, 2023, the 1-month, 3- month and 6-month U.S. Dollar LIBOR settings will cease to be provided or, subject to the FCA’s consideration of the case, be provided on a synthetic basis and no longer be representative of the underlying market and economic reality they are intended to measure and that representativeness will not be restored. There is no assurance that dates announced by the FCA will not change or that the administrator of LIBOR and/or regulators will not take further action that could impact the availability, composition, or characteristics of LIBOR or the currencies and/or tenors for which LIBOR is published. Each party to this agreement should consult its own advisors to stay informed of any such developments. Public and private sector industry initiatives are currently underway to identify new or alternative reference rates to be used in place of LIBORa Loan denominated in Dollars may be derived from an interest rate benchmark that may be discontinued or is, or may in the future become, the subject of regulatory reform. Upon the occurrence of a Benchmark Transition Event or an Early Opt-In Election, Section 2.13(b) and 2.13(cb) provide theprovides a mechanism for determining an alternative rate of interest. The Administrative Agent will promptly notify the Borrower, pursuant to Section 2.13(e), of any change to the reference rate upon which the interest rate on Eurodollar Loans is based. However, the Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to, the administration, submission, performance or any other matter related to LIBOR or other rates in the definition of “Eurodollar Base Rate”any interest rate used in this Agreement, or with respect to any alternative or successor rate thereto, or replacement rate thereof (including, without limitation, (i) any such alternative, successor or replacement rate implemented pursuant to Section 2.13(b) or (c), whether upon the occurrence of a Benchmark Transition Event or an Early Opt-In Election, and (ii) the implementation of any Benchmark Replacement Conforming Changes pursuant to Section 2.13(d)),, including without limitation, whether the composition or characteristics of any such alternative, successor or replacement reference rate will be similar to, or produce the same value or economic equivalence of, the Eurodollar Base Rateexisting interest rate being replaced or have the same volume or liquidity as did the London interbank offeredany existing interest rate prior to its discontinuance or unavailability. The Administrative Agent and its affiliates and/or other related entities may engage in transactions that affect the calculation of any interest rate used in this Agreement or any alternative, successor or alternative rate (including any Benchmark Replacement) and/or any relevant adjustments thereto, in each case, in a manner adverse to the Borrower. The Administrative Agent may select information sources or services in its reasonable discretion to ascertain any interest rate used in this Agreement, any component thereof, or rates referenced in the definition thereof, in each case pursuant to the terms of this Agreement, and shall have no liability to the Borrower, any Lender or any other person or entity for damages of any kind, including direct or indirect, special, punitive, incidental or consequential damages, costs, losses or expenses (whether in tort, contract or otherwise and whether at law or in equity), for any error or calculation of any such rate (or component thereof) provided by any such information source or service.

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Section 12.AMOUNT AND TERMS OF THE TERM LOANS

1.1Loans.

(a) Subject to the terms and conditions set forth herein, each 364-Day Tranche Lender (severally and not jointly) agrees to make a term loan (the “364-Day Tranche Loans”) to the Borrower in Dollars on the Effective Date in an amount equal to such 364-Day Tranche Lender’s 364-Day Tranche Commitment. Loans under the 364-Day Tranche may be ABR Loans or Eurodollar Loans, as further provided herein. 364-Day Tranche Loans borrowed under this Section 2.1(a) and paid or prepaid may not be reborrowed.

(a)[Reserved].

(b)Subject to the terms and conditions set forth herein, each 18-Month Tranche Lender (severally and not jointly) agrees to make a term loan (the “18-Month Tranche Loans”) to the Borrower in Dollars on the Effective Date in an aggregate amount equal to the amount of such 18-Month Tranche Lender’s 18-Month Tranche Commitment. Loans under the 18-Month Tranche may be ABR Loans or Eurodollar RateTerm Benchmark Loans, as further provided herein. 18-Month Tranche Loans borrowed under this Section 2.1(b)2.1(b) and paid or prepaid may not be reborrowed. As of the Amendment No. 1 Effective Date, a portion of the 18-Month Tranche Loans in an aggregate amount of $1,315,735,897.44 (the “18-Month Tranche Loans (Tranche A)”) shall have an 18-Month Tranche Maturity Date of October 1, 2022 and a portion of the 18-Month Tranche Loans in an aggregate amount of $184,264,102.56 (the “18-Month Tranche Loans (Tranche B)”) shall have an 18-Month Tranche Maturity Date of January 1, 2022. As of the Amendment No. 2 Effective Date, the 18-Month Tranche Loans (Tranche B) shall have an 18-Month Tranche Maturity Date of October 1, 2022. As of the Amendment No. 3 Effective Date, all 18-Month Tranche Loans shall have an 18-Month Tranche Maturity Date of January 1, 2023.

1.2Procedures for Borrowing. The Borrower may borrow the Loans on the Effective Date (so long as the Effective Date is a Business Day), provided that the Borrower shall give the Administrative Agent irrevocable notice (which notice must be received by the Administrative Agent (a) prior to 12:00 Noon, New York City time, three Business Days prior to the Effective Date, in the case of EurodollarTerm Benchmark Loans, or (b) prior to 1:00 P.M., New York City time, one Business Day prior to the Effective Date, in the case of ABR Loans) specifying (i) the amount and Type of Loans to be borrowed on the Effective Date and (ii) in the case of EurodollarTerm Benchmark Loans, the respective amounts of each such Type of Loan and the respective lengths of the initial Interest Period therefor. Upon receipt of any such notice from the Borrower, the Administrative Agent shall promptly notify each Lender thereof. Each Lender will make the amount of its pro rata share of each borrowing available to the Administrative Agent for the account of the Borrower at the Funding Office prior to 10:00 A.M., New York City time, on the Effective Date requested by the Borrower in funds immediately available to the Administrative Agent. Such borrowing will then be made available to the Borrower by the Administrative Agent crediting the account of the Borrower on the books of such office with the aggregate of the amounts made available to the Administrative Agent by the Lenders and in like funds as received by the Administrative Agent

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1.3[Reserved].

1.4[Reserved].

1.5[Reserved].

1.6Fees, Etc.

(a)The Borrower agrees to pay to the Administrative Agent, for the account of each Lender (other than a Defaulting Lender to the extent provided in Section 2.20), any fees payable in the amounts and at the times separately agreed upon between the Borrower and the Lenders.

(b)The Borrower agrees to pay to the Administrative Agent the fees in the amounts and on the dates as set forth in any written, duly executed fee agreements with the Administrative Agent and to perform any other obligations contained therein.

(c)On JuneApril 1, 2022, the Borrower agrees to pay to the Administrative Agent, for the account of each Lender that holds any 18-Month Tranche Loans (Tranche A) outstanding on such date, a fee equal to 0.075% of the principal amount of such Loans.

1.7Termination of Commitments. The Commitments shall automatically terminate in full on the Effective Date after the proceeds of the Loans have been made available to the Borrower.

1.8Prepayments.

(a)Optional. The Borrower may at any time and from time to time prepay the Loans, in whole or in part, without premium or penalty, upon irrevocable notice delivered to the Administrative Agent no later than 12:00 Noon, New York City time, three Business Days prior thereto, in the case of EurodollarTerm Benchmark Loans, and no later than 2:00 p.m., New York City time, one Business Day prior thereto, in the case of ABR Loans, which notice shall specify the date and amount of prepayment and whether the prepayment is of EurodollarTerm Benchmark Loans or ABR Loans. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof. If any such notice is given, the amount specified in such notice shall be due and payable on the date specified therein, together with accrued interest to such date on the amount prepaid. Partial prepayments of Loans shall be in an aggregate principal amount of $1,000,000 or a whole multiple of $500,000 in excess thereof. Notwithstanding the foregoing, any notice of prepayment delivered in connection with any refinancing of all of the Loans with the proceeds of such refinancing or of any other incurrence of Indebtedness or the occurrence of some other identifiable event or condition, may be, if expressly so stated to be, contingent upon the consummation of such refinancing or incurrence or occurrence of such other identifiable event or condition and may be revoked by the Borrower, subject to compliance with the obligations under Section 2.17 in connection with any such revocation, in the event such contingency is not met. Each prepayment of Loans under this clause (a) shall be applied to the prepayment in full of the aggregate principal amount and any accrued but unpaid interest with respect to the 364-Day Tranche Loans before being applied to prepay the aggregate principal

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amount and any accrued but unpaid interest with respect to the 18-Month Tranche Loans and shall be accompanied by accrued interest and fees on the amount prepaid to the date fixed for prepayment, plus, in the case of any EurodollarTerm Benchmark Loans that are prepaid on any day other than the last day of the Interest Period applicable to it, the Borrower shall pay any amounts due to the Lenders as a result thereof pursuant to Section 2.17.

(b)Mandatory. So long as (i) the commitments in respect of each of the Bridge Facilities have been terminated without the funding of any loans thereunder or (ii) the loans and any accrued interest, fees and other obligations under the Bridge Facilities have been paid in full, in the event that the Borrower or any of its Subsidiaries receives any Net Cash Proceeds arising from any Debt Issuance, then the Borrower shall prepay the Loans hereunder in an amount equal to 100% of such Net Cash Proceeds not later than five (5) Business Days following the receipt by the Borrower or such Subsidiary of such Net Cash Proceeds. The Borrower shall promptly (and not later than five (5) Business Days following receipt thereof) notify the Administrative Agent of the receipt by the Borrower or any Subsidiary, as applicable, of such Net Cash Proceeds and such notice shall be accompanied by a reasonably detailed calculation of the Net Cash Proceeds. Each prepayment of Loans under this clause (b) shall be applied to the prepayment in full of the aggregate principal amount and any accrued but unpaid interest with respect to the 364-Day Tranche Loans before being applied to prepay the aggregate principal amount and any accrued but unpaid interest with respect to the 18-Month Tranche Loans and shall be accompanied by accrued interest and fees on the amount prepaid to the date fixed for prepayment, plus, in the case of any EurodollarTerm Benchmark Loans that are prepaid on any day other than the last day of the Interest Period applicable to it, the Borrower shall pay any amounts due to the Lenders as a result thereof pursuant to Section 2.17.

1.9Conversion and Continuation Options.

(a)The Borrower may elect from time to time to convert EurodollarTerm Benchmark Loans to ABR Loans by giving the Administrative Agent prior irrevocable notice of such election no later than 12:00 Noon, New York City time, on the Business Day preceding the proposed conversion date, provided that any such conversion of EurodollarTerm Benchmark Loans may only be made on the last day of an Interest Period with respect thereto. The Borrower may elect from time to time to convert ABR Loans to EurodollarTerm Benchmark Loans by giving the Administrative Agent prior irrevocable notice of such election no later than 12:00 Noon, New York City time, on the third Business Day preceding the proposed conversion date (which notice shall specify the length of the initial Interest Period therefor), provided that no ABR Loan may be converted into a EurodollarTerm Benchmark Loan when any Event of Default has occurred and is continuing and the Required Lenders have determined in their sole discretion not to permit such conversions. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.

(b)Any EurodollarTerm Benchmark Loan may be continued as such upon the expiration of the then current Interest Period with respect thereto by the Borrower giving irrevocable notice to the Administrative Agent, in accordance with the applicable provisions of the defined term “Interest Period”, of the length of the next Interest Period to be applicable to such Loans,

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provided that no EurodollarTerm Benchmark Loan may be continued as such when any Event of Default has occurred and is continuing and the Required Lenders have determined in their sole discretion not to permit such continuations; provided, further, that if the Borrower shall fail to give any required notice as described above in this paragraph, subject to the preceding proviso, such Loans shall be automatically continued as EurodollarTerm Benchmark Loans with an Interest Period of one month on the last day of such then expiring Interest Period.Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.

1.10Limitations on EurodollarTerm Benchmark Tranches. Notwithstanding anything to the contrary in this Agreement, all borrowings, conversions and continuations of EurodollarTerm Benchmark Loans and all selections of Interest Periods shall be in such amounts and be made pursuant to such elections so that (a) after giving effect thereto, the aggregate principal amount of the EurodollarTerm Benchmark Loans comprising each EurodollarTerm Benchmark Tranche shall be equal to $1,000,000 or a whole multiple of $500,000 in excess thereof and (b) no more than 5 EurodollarTerm Benchmark Tranches shall be outstanding at any one time.

1.11Interest Rates and Payment Dates.

(a)Each EurodollarTerm Benchmark Loan shall bear interest for each day during each Interest Period with respect thereto at a rate per annum equal to the Eurodollar RateTerm Benchmark determined for such day plus the Applicable Margin.

(b)Each ABR Loan shall bear interest at a rate per annum equal to the ABR plus the Applicable Margin.

(c)(i) If all or a portion of the principal amount of the Loans shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a default rate per annum equal to the rate that would otherwise be applicable thereto pursuant to the foregoing provisions of this Section plus 2% and (ii) if all or a portion of any interest payable on the Loans or any other fee payable in connection herewith (excluding any expenses or other indemnity) shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a default rate per annum equal to the rate then applicable to ABR Loans plus 2%, in each case, with respect to clauses (i) and (ii) above, from the date of such non-payment until such amount is paid in full (as well after as before judgment).

(d)Interest shall be payable in arrears on each Interest Payment Date, provided that interest accruing pursuant to Section 2.11(c) shall be payable from time to time on demand.

(e)The amount of each interest payment received by the Administrative Agent under the applicable Senior Bond shall be deemed to be a payment of interest payable by the Borrower hereunder and shall reduce, dollar-for-dollar, the amount of interest then owing by the Borrower hereunder.

1.12Computation of Interest and Fees.

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(a)Interest and fees payable pursuant hereto shall be calculated on the basis of a 360-day year for the actual days elapsed, except that, with respect to ABR Loans the rate of interest on which is calculated on the basis of ABR, the interest thereon shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed. The Administrative Agent shall as soon as practicable notify the Borrower and the relevant Lenders of each determination of a Eurodollar RateTerm Benchmark. Any change in the interest rate on a Loan resulting from a change in the ABR or the Eurocurrency Reserve RequirementsTerm Benchmark shall become effective as of the opening of business on the day on which such change becomes effective. The Administrative Agent shall as soon as practicable notify the Borrower and the relevant Lenders of the effective date and the amount of each such change in interest rate.

(b)Each determination of an interest rate by the Administrative Agent pursuant to any provision of this Agreement shall constitute prima facie evidence of such amounts. The Administrative Agent shall, at the request of the Borrower or any Lender, deliver to the Borrower or such Lender a statement showing the quotations used by the Administrative Agent in determining any interest rate pursuant to Section 2.11(a).

1.13Inability to Determine Interest Rate.

(a)Subject to clauses (b), (c), (d), (e),and (f) and (g) of this Section 2.13, if prior to the commencement of any Interest Period for a Eurodollar Loan:

Section 13.the Administrative Agent determines (which determination shall be conclusive absent manifest error) (A) prior to the commencement of any Interest Period for a Term Benchmark Borrowing, that adequate and reasonable means do not exist for ascertaining the EurodollarAdjusted Term SOFR Rate or the Eurodollar BaseTerm SOFR Rate, as applicable (including because the Eurodollar ScreenTerm SOFR Reference Rate is not available or published on a current basis), for such Interest Period, provided that no Benchmark Transition Event shall have occurred at such timeor (B) at any time, that adequate and reasonable means do not exist for ascertaining the applicable Adjusted Daily Simple SOFR, Daily Simple SOFR; or

Section 14.the Administrative Agent is advised by the Required Lenders that the Eurodollar Rate or the Eurodollar Base Rate, as applicable,(A) prior to the commencement of any Interest Period for a Term Benchmark Borrowing, the Adjusted Term SOFR Rate for such Interest Period will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in the applicable borrowingsuch Borrowing for such Interest Period or (B) at any time, Adjusted Daily Simple SOFR will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in such Borrowing;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone, telecopy or electronic mail as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (A) any notice from the Borrower to the Administrative Agent that requests the conversion of any Loans to, or continuation of any Loans as, a Eurodollar borrowing shall be ineffectiveTerm Benchmark Borrowing shall instead be deemed to request the conversion of any Loans to, or continuation

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of any Loans as, (x) a RFR Borrowing so long as the Adjusted Daily Simple SOFR is not also the subject of Section 2.13(a)(i) or (ii) above or (y) an ABR Borrowing if the Adjusted Daily Simple SOFR also is the subject of Section 2.13(a)(i) or (ii) above and (B) if any borrowing notice delivered pursuant to Section 2.2 requests a borrowing of EurodollarTerm Benchmark Loans, such borrowing shall be made as an ABR Loan(x) a RFR Loan so long as the Adjusted Daily Simple SOFR is not also the subject of Section 2.13(a)(i) or (ii) above or (y) an ABR Borrowing if the Adjusted Daily Simple SOFR also is the subject of Section 2.13(a)(i) or (ii) above; provided that if the circumstances giving rise to such notice affect only one Type of borrowings, then the other Type of borrowings shall be permitted.

(a)Replacing USD LIBOR. Notwithstanding anything to the contrary herein or in any other Loan Document, on March 5, 2021 the Financial Conduct Authority (“FCA”), the regulatory supervisor of the Eurodollar Base Rate’s administrator (“IBA”), announced in a public statement the future cessation or loss of representativeness of overnight/Spot Next, 1-week, 1-month, 3-month, 6-month and 12-month Eurodollar Base Rate tenor settings. On the earlier of (i) the date that all Available Tenors of the Eurodollar Base Rate have either permanently or indefinitely ceased to be provided by IBA or have been announced by the FCA pursuant to public statement or publication of information to be no longer representative and (ii) the Early Opt-in Effective Date, if the then-current Benchmark is the Eurodollar Base Rate, the Benchmark(and any Swap Agreement shall be deemed not to be a “Loan Document” for purposes of this Section 2.13), if a Benchmark Transition Event and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then (x) if a Benchmark Replacement is determined in accordance with clause (1) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Loan Document in respect of any setting of such Benchmark on such day and allsetting and subsequent Benchmark settings without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document. If theand (y) if a Benchmark Replacement is Daily Simple SOFR, all interest payments will be payable on a monthly basis.

(c) determined in accordance with clause (2) of Replacing Future Benchmarks. Upon the occurrence of a Benchmark Transition Event, the the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace the then-currentsuch Benchmark for all purposes hereunder and under any Loan Document in respect of any Benchmark setting at or after 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Required Lenders. Upon the occurrence of a Benchmark Transition Event, the Borrower may revoke any request for a borrowing of, conversion to or continuation of Loans to be made, converted or continued that would bear interest by reference to such Benchmark until the Borrower’s receipt of notice from the Administrative Agent that a Benchmark Replacement has replaced such Benchmark, and, failing that, the Borrower will be deemed to have converted any such request into a request for a borrowing of or conversion to ABR Loans. During

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the period referenced in the foregoing sentence, the component of ABR based upon the Benchmark will not be used in any determination of ABR.of each affected Class.

(b)(d) Benchmark Replacement Conforming Changes. In connection with the implementation and administration of a Benchmark Replacement,Notwithstanding anything to the contrary herein or in any other Loan Document, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Loan Document.

(c)(e) Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (i) (i)any occurrence of a Benchmark Transition Event, (ii)the implementation of any Benchmark Replacement and (ii), (iii)the effectiveness of any Benchmark Replacement Conforming Changes. For the avoidance of doubt, any notice required to be delivered by the Administrative Agent as set forth in this Section 2.13 may be provided, at the option of the Administrative Agent (in its sole discretion), in one or more notices and may be delivered together with, or as part of any amendment which implements any Benchmark Replacement or Benchmark Replacement Conforming Changes, (iv)the removal or reinstatement of any tenor of a Benchmark pursuant to clause (f) below and (v)the commencement or conclusion of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section 2.13, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party heretoto this Agreement or any other Loan Document, except, in each case, as expressly required pursuant to this Section 2.13.

(d)(f) Unavailability of Tenor of Benchmark. AtNotwithstanding anything to the contrary herein or in any other Loan Document, at any time (including in connection with the implementation of a Benchmark Replacement), (i) (i) if the then-current Benchmark is a term rate (including the Term SOFR or Eurodollar Base Rate)Rate) and either (A) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (B) the regulatory supervisor for the administrator of such Benchmark has provided a public statement or publication of information announcing that any tenor for such Benchmark is or will be no longer representative, then the Administrative Agent may remove any tenor of suchmodify the definition of “Interest Period” for any Benchmark that issettings at or after such time to remove such unavailable or non-representative fortenor and (ii) if a tenor that was removed pursuant to clause (i) above either (A)is subsequently displayed on a screen or information service for a Benchmark (including a Benchmark Replacement) settings and (ii)or (B)is not, or is no longer, subject to an announcement that it is or will no longer be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” for all Benchmark settings at or after such time to reinstate any such previously removed tenor for Benchmark (including Benchmark Replacement) settings.

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(g) Disclaimer. The Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to (i) the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of “Eurodollar Rate” or “Eurodollar Base Rate” or with respect to any alternative or successor rate thereto, or replacement rate thereof (including, without limitation any Benchmark Replacement implemented hereunder), (ii) the composition or characteristics of any Benchmark Replacement, including whether it is similar to, or produces the same value or economic equivalence to the Eurodollar Base Rate (or any other Benchmark) or have the same volume or liquidity as did the Eurodollar Base Rate (or any other Benchmark), (iii) any actions or use of its discretion or other decisions or determinations made with respect to any matters covered by this Section 2.13 including, without limitation, whether or not a Benchmark Transition Event has occurred, the removal or lack thereof of unavailable or non-representative tenors, the implementation or lack thereof of any Benchmark Replacement Conforming Changes, the delivery or non-delivery of any notices required by clause (e) above or otherwise in accordance herewith, and (iv) the effect of any of the foregoing provisions of this Section 2.13.

(e)Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a Term Benchmark Borrowing or conversion to or continuation of Term Benchmark Loans to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any request for a Term Benchmark Borrowing into a request for a Borrowing of or conversion to (A) an RFR Borrowing so long as the Adjusted Daily Simple SOFR is not the subject of a Benchmark Transition Event or (B) an ABR Borrowing if the Adjusted Daily Simple SOFR is the subject of a Benchmark Transition Event. During any Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of ABR based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of ABR. Furthermore, if any Term Benchmark Loan is outstanding on the date of the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period with respect to a Relevant Rate applicable to such Term Benchmark Loan or RFR Loan, then until such time as a Benchmark Replacement is implemented pursuant to this Section 2.13, any Term Benchmark Loan shall on the last day of the Interest Period applicable to such Loan (or the next succeeding Business Day if such day is not a Business Day), be converted by the Administrative Agent to, and shall constitute, (x) an RFR Borrowing so long as the Adjusted Daily Simple SOFR is not the subject of a Benchmark Transition Event or (y) an ABR Loan if the Adjusted Daily Simple SOFR is the subject of a Benchmark Transition Event, on such day.

1.2Pro Rata Treatment and Payments; Notes.

(a)[Reserved].

(b)Each payment (including each prepayment) by the Borrower on account of principal of and interest on the Loans (other than, for the avoidance of doubt, payment in full of all principal and interest due with respect to the 18-Month Tranche Loans (Tranche B) on or prior to the 18-Month Tranche

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Maturity Date for such Loans) shall be made pro rata(i) in the case of the 364-Day Tranche Loans, according to the respective outstanding principal amounts of the 364-Day Tranche Loans then held by the 364-Day Tranche Lenders and (ii) in the case of the 18-Month Tranche Loans, according to the respective outstanding principal amounts of the 18-Month Tranche Loans then held by the 18-Month Tranche Lenders.

(c)Notwithstanding anything to the contrary herein, all payments (including prepayments) to be made by the Borrower hereunder, whether on account of principal, interest, fees or otherwise, shall be made without setoff or counterclaim and shall be made prior to 4:00 P.M., New York City time, on the due date thereof to the Administrative Agent, for the account of the Lenders, as applicable, at the Funding Office, in Dollars and in immediately available funds. The Administrative Agent shall distribute such payments to the Lenders promptly upon receipt in like funds as received. If any payment hereunder (other than payments on the EurodollarTerm Benchmark Loans) becomes due and payable on a day other than a Business Day, such payment shall be extended to the next succeeding Business Day. If any payment on a EurodollarTerm Benchmark Loan becomes due and payable on a day other than a Business Day, the maturity thereof shall be extended to the next succeeding Business Day unless the result of such extension would be to extend such payment into another calendar month, in which event such payment shall be made on the immediately preceding Business Day. In the case of any extension of any payment of principal pursuant to the preceding two sentences, interest thereon shall be payable at the then applicable rate during such extension.

(d)Unless the Administrative Agent shall have been notified in writing by any Lender prior to a borrowing that such Lender will not make the amount that would constitute its share of such borrowing available to the Administrative Agent, the Administrative Agent may assume that such Lender is making such amount available to the Administrative Agent, and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower a corresponding amount. If such amount is not made available to the Administrative Agent by the required time on the Effective Date, such Lender shall pay to the Administrative Agent, on demand, such amount with interest thereon, at a rate equal to the greater of (i) the Federal Funds EffectiveNYFRB Rate and (ii) a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation, for the period until such Lender makes such amount immediately available to the Administrative Agent. A certificate of the Administrative Agent submitted to any Lender with respect to any amounts owing under this paragraph shall be conclusive in the absence of manifest error. If such Lender’s share of such borrowing is not made available to the Administrative Agent by such Lender within three Business Days after the Effective Date, the Administrative Agent shall also be entitled to recover such amount with interest thereon at the rate per annum applicable to ABR Loans from the Borrower within 30 days after written demand therefor.

(e)Unless the Administrative Agent shall have been notified in writing by the Borrower prior to the date of any payment due to be made by the Borrower hereunder that the Borrower will not make such payment to the Administrative Agent, the Administrative Agent may assume that the Borrower is making such payment, and the Administrative Agent may, but shall not be

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required to, in reliance upon such assumption, make available to the Lenders their respective pro rata shares of a corresponding amount. If such payment is not made to the Administrative Agent by the Borrower within three Business Days after such due date, the Administrative Agent shall be entitled to recover, on demand, from each Lender to which any amount which was made available pursuant to the preceding sentence, such amount with interest thereon at the rate per annum equal to the daily average Federal Funds EffectiveNYFRB Rate. Nothing herein shall be deemed to limit the rights of the Administrative Agent or any Lender against the Borrower.

(f)The Borrower agrees that, upon the request to the Administrative Agent by any Lender, the Borrower will promptly execute and deliver to such Lender a promissory note (a “Note”) of the Borrower evidencing any Loans (or any portion thereof) of such Lender, substantially in the form of Exhibit H, with appropriate insertions as to date and principal amount; provided, that delivery of Notes shall not be a condition precedent to the occurrence of the Effective Date or the making of the Loans on the Effective Date.

(g)If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.14(d), then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent hereunder for the account of such Lender for the benefit of the Administrative Agent to satisfy such Lender’s obligations to the Administrative Agent, as the case may be, under such Section until all such unsatisfied obligations are fully paid, and/or (ii) so long as such Lender is a Defaulting Lender, hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

1.3Change of Law.

(a)If a Change of Law shall:

Section 15.subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its Loans, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

Section 16.impose, modify or hold applicable any reserve, special deposit, compulsory loan, Federal Deposit Insurance Corporation insurance charge or other similar insurance charge or similar requirement against assets held by, deposits or other liabilities in or for the account of, advances, loans or other extensions of credit by, or any other acquisition of funds by, any Lender that is not otherwise included in the determination of the EurodollarTerm Benchmark Rate, which requirements are generally applicable to advances, loans and other extensions of credit made by such Lender; or

Section 17.impose on any Lender any other condition that is generally applicable to loans made by such Lender or participations therein;

and the result of any of the foregoing is to increase the cost to such Lender or such other Recipient, by an amount that such Lender or such other Recipient deems to be material,

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of making, converting into, continuing or maintaining the Loans, or to reduce any amount receivable hereunder in respect thereof, then, in any such case, the Borrower shall promptly pay such Lender or such other Recipient, within ten Business Days after its demand, any additional amounts necessary to compensate such Lender or such other Recipient for such increased cost or reduced amount receivable. If any Lender or other Recipient becomes entitled to claim any additional amounts pursuant to this paragraph, it shall promptly notify the Borrower (with a copy to the Administrative Agent) of the event by reason of which it has become so entitled; provided, however, that no Lender or other Recipient shall be entitled to demand such compensation more than 90 days following (x) the last day of the Interest Period in respect of which such demand is made or (y) the repayment of the Loan in respect of which such demand is made. Notwithstanding any other provision herein, no Lender shall demand compensation pursuant to this Section 2.15 if it shall not at the time be the general policy or practice of such Lender to demand such compensation from similarly situated borrowers (to the extent that such Lender has the right to do so under its credit facilities with similarly situated borrowers).

(a)If any Lender shall have determined that a Change of Law regarding capital or liquidity requirements shall have the effect of reducing the rate of return on such Lender’s capital or the capital of any corporation controlling such Lender as a consequence of its obligations hereunder to a level below that which such Lender or such corporation could have achieved but for such Change of Law (taking into consideration such Lender’s or such corporation’s policies with respect to capital adequacy or liquidity) by an amount deemed by such Lender to be material, then from time to time, after submission by such Lender to the Borrower (with a copy to the Administrative Agent) of a written request therefor, the Borrower shall pay to such Lender such additional amount or amounts as will compensate such Lender or such corporation for such reduction.

(b)A certificate as to any additional amounts payable pursuant to this Section 2.15 submitted by any Lender or any other Recipient to the Borrower (with a copy to the Administrative Agent) shall constitute prima facie evidence of such costs or amounts. Notwithstanding anything to the contrary in this Section 2.15, the Borrower shall not be required to compensate a Lender or any other Recipient pursuant to this Section 2.15 for any amounts incurred more than six months prior to the date that such Lender or such other Recipient notifies the Borrower of such Lender’s or such other Recipient’s intention to claim compensation therefor; provided that, if the circumstances giving rise to such claim have a retroactive effect, then such six-month period shall be extended to include the period of such retroactive effect not to exceed twelve months. The obligations of the Borrower pursuant to this Section 2.15 shall survive for 90 days after the termination of this Agreement and the payment of the Loans and all other amounts then due and payable hereunder.

1.2Taxes.

(a)Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall be made without deduction or withholding for any Taxes, except as required by applicable laws. If any applicable laws (as determined in the good faith discretion of the Borrower or Administrative Agent making the payment) require the deduction or withholding of any Tax from any such payment, then (A) the Borrower or Administrative Agent, as applicable shall withhold or make such deductions as are determined by the Borrower or the Administrative Agent to be required,

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(B) the Borrower or Administrative Agent, as applicable shall timely pay the full amount withheld or deducted to the relevant Governmental Authority in accordance with such laws, and (C) to the extent that the withholding or deduction is made on account of Indemnified Taxes, the sum payable by the Borrower shall be increased as necessary so that after any required withholding or the making of all required deductions (including deductions applicable to additional sums payable under this Section 2.16) the applicable Recipient receives an amount equal to the sum it would have received had no such withholding or deduction been made.

(b)Without limiting the provisions of subsection (a) above, the Borrower shall timely pay to the relevant Governmental Authority in accordance with applicable law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(c)(i) The Borrower shall, and does hereby, indemnify each Recipient, and shall make payment in respect thereof within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 2.16) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender or another Recipient (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender or another Recipient, shall be conclusive absent manifest error.

Section 18.Each Lender shall, and does hereby, severally indemnify, and shall make payment in respect thereof within 10 days after demand therefor, (x) the Administrative Agent against any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (y) the Administrative Agent against any Taxes attributable to such Lender’s failure to comply with the provisions of Section 10.6(c)(iii) relating to the maintenance of a Participant Register and (z) the Administrative Agent against any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender, as the case may be, under this Agreement or any other Loan Document against any amount due to the Administrative Agent under this clause (ii).

(a)Upon request by the Borrower or the Administrative Agent, as the case may be, after any payment of Taxes by the Borrower or by the Administrative Agent to a Governmental Authority as provided in this Section 2.16, the Borrower shall deliver to the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by laws to report such

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payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(b)(i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Sections 2.16(e)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

Section 19.Without limiting the generality of the foregoing,

(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(I)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed copies of IRS Form W-8BEN or W-8BEN-E, as applicable, establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN or W-8BEN-E, as applicable,

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establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(II)executed copies of IRS Form W-8ECI;

(III)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit G-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed copies of IRS Form W-8BEN or W-8BEN-E, as applicable; or

(IV)to the extent a Foreign Lender is not the beneficial owner, executed copies of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN or W-8BEN-E, as applicable, a U.S. Tax Compliance Certificate substantially in the form of Exhibit G-2 or Exhibit G-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit G-4 on behalf of each such direct and indirect partner.

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

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(D)if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3) (C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the Effective Date.

Section 20.Each Lender agrees that if any form or certification it previously delivered pursuant to this Section 2.16 expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(a)At no time shall the Administrative Agent have any obligation to file for or otherwise pursue on behalf of a Lender, any refund of Taxes withheld or deducted from funds paid for the account of such Lender, as the case may be. If any Recipient determines, in its sole discretion exercised in good faith, that it has received a refund of, or credit with respect to, any Taxes as to which it has been indemnified pursuant to this Section 2.16 (including by the payment of additional amounts pursuant to this Section 2.16), it shall pay to the Borrower an amount equal to such refund or credit (but only to the extent of indemnity payments made under this Section 2.16 with respect to the Taxes giving rise to such refund or credit), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund or credit). The Borrower, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this paragraph (f) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event such indemnified party is required to repay such refund or credit to such Governmental Authority. Notwithstanding anything to the contrary in this paragraph (f), in no event will the indemnified party be required to pay any amount to the Borrower pursuant to this paragraph (f) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund or credit had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This paragraph (f) shall not be construed to require any Recipient to make available its tax returns (or any other information relating to its Taxes that it deems confidential) to the Borrower or any other Person.

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(b)Each party’s obligations under this Section 2.16 shall survive for one year after the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

1.2Indemnity. The Borrower agrees to indemnify each Lender for, and to hold each Lender harmless from, any loss (other than the loss of Applicable Margin) or expense that such Lender may sustain or incur as a consequence of (a) default by the Borrower in making a borrowing of, conversion into or continuation of EurodollarTerm Benchmark Loans after the Borrower has given a notice requesting the same in accordance with the provisions of this Agreement, (b) default by the Borrower in making any prepayment of or conversion from EurodollarTerm Benchmark Loans after the Borrower has given a notice thereof in accordance with the provisions of this Agreement or (c) the making of a prepayment of EurodollarTerm Benchmark Loans on a day that is not the last day of an Interest Period with respect thereto. A certificate as to any amounts payable pursuant to this Section submitted to the Borrower by any Lender shall be conclusive in the absence of manifest error. This covenant shall survive for 90 days after the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

1.3Change of Lending Office. Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.15 or 2.16 with respect to such Lender, it will, if requested by the Borrower, use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event with the object of avoiding the consequences of such event; provided, that such designation is made on terms that, in the sole but reasonable judgment of such Lender, cause such Lender and its lending office(s) to suffer no unreimbursed economic disadvantage or any legal or regulatory disadvantage, and provided, further, that nothing in this Section shall affect or postpone any of the obligations of the Borrower or the rights of any Lender pursuant to Section 2.15 or 2.16.

1.4Replacement of Lenders. The Borrower shall be permitted to replace any Lender that (a) requests (on its behalf or any of its Participants) reimbursement for amounts owing pursuant to Section 2.15 or 2.16, (b) provides notice under Section 2.21 or (c) becomes a Defaulting Lender, with a replacement financial institution; provided that (i) such replacement does not conflict with any Requirement of Law, (ii) no Event of Default shall have occurred and be continuing at the time of such replacement, (iii) prior to any such replacement, such Lender shall have taken no action under Section 2.18 which eliminates the continued need for payment of amounts owing pursuant to Section 2.15 or 2.16, (iv) the replacement financial institution shall purchase, at par, all Loans and other amounts owing to such replaced Lender on or prior to the date of replacement, (v) the Borrower shall be liable to such replaced Lender under Section 2.17 if any EurodollarTerm Benchmark Loan owing to such replaced Lender shall be purchased other than on the last day of the Interest Period relating thereto, (vi) the replacement financial institution, if not already a Lender, shall be reasonably satisfactory to the Administrative Agent, (vii) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 10.6 (provided that the Borrower shall be obligated to pay the registration and processing fee referred to therein), (viii) until such time as such replacement shall be consummated, the Borrower shall pay all additional amounts (if any) required pursuant to Section 2.15 or 2.16, as the case may be, and (ix) any such replacement shall not be deemed to be a waiver of any rights that the Borrower,

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the Administrative Agent or any other Lender shall have against the replaced Lender.

1.5Defaulting Lenders. Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as that Lender is no longer a Defaulting Lender, to the extent permitted by applicable law:

(a)any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Section 7 or otherwise, and including any amounts made available to the Administrative Agent by that Defaulting Lender pursuant to Section 9.7), shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third, if so determined by the Borrower with the consent of the Administrative Agent, not to be unreasonably withheld, to be held in a non-interest bearing deposit account and released in order to satisfy obligations of that Defaulting Lender to fund Loans under this Agreement; fourth, to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; fifth, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; and sixth, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if such payment is a payment of the principal amount of the Loans in respect of which that Defaulting Lender has not fully funded its appropriate share such payment shall be applied solely to pay the Loans of all non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Loans of that Defaulting Lender. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 2.20(a) shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto;

(b)[Reserved];

(c)[Reserved];

(d)[Reserved]; and

(e)that Defaulting Lender’s right to approve or disapprove any amendment, supplement, modification, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of “Required Lenders” and Section 10.1.

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If the Borrower and the Administrative Agent reasonably determine in writing that a Defaulting Lender should no longer be deemed to be a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein (which may include arrangements with respect to any cash collateral), that Lender will, to the extent applicable, purchase that portion of outstanding Loans of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Loans to be held on a pro rata basis by the Lenders in accordance with their Percentages, whereupon that Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.

2.21 Illegality. If any Lender determines that any Law has made it unlawful, or that any Governmental Authority has asserted that it is unlawful, for any Lender or its applicable lending office to make, maintain, or fund Loans whose interest is determined by reference to the Eurodollar Rate, or to determine or charge interest rates based upon the Eurodollar Rate, or any Governmental Authority has imposed material restrictions on the authority of such Lender to purchase or sell, or to take deposits of, Dollars in the London interbank market, then, upon notice thereof by such Lender to the Borrower (through the Administrative Agent), (a) any obligation of such Lender to make or continue Eurodollar Loans or to convert ABR Loans to Eurodollar Loans shall be suspended, and (b) if such notice asserts the illegality of such Lender making or maintaining ABR Loans the interest rate on which is determined by reference to the Eurodollar Rate component of the ABR, the interest rate on which ABR Loans of such Lender shall, if necessary to avoid such illegality, be determined by the Administrative Agent without reference to the Eurodollar Rate component of the ABR, in each case until such Lender notifies the Administrative Agent and the Borrower that the circumstances giving rise to such determination no longer exist. Upon receipt of such notice, (i) the Borrower shall, upon demand from such Lender (with a copy to the Administrative Agent), prepay or, if applicable, convert all Eurodollar Loans of such Lender to ABR Loans (the interest rate on which ABR Loans of such Lender shall, if necessary to avoid such illegality, be determined by the Administrative Agent without reference to the Eurodollar Rate component of the ABR), either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Loans to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Loans and (ii) if such notice asserts the illegality of such Lender determining or charging interest rates based upon the Eurodollar Rate, the Administrative Agent shall during the period of such suspension compute the ABR applicable to such Lender without reference to the Eurodollar Rate component thereof until the Administrative Agent is advised in writing by such Lender that it is no longer illegal for such Lender to determine or charge interest rates based upon the Eurodollar Rate. Upon any such prepayment or conversion, the Borrower shall also pay accrued interest on the amount so prepaid or converted, together with any additional amounts required pursuant to Section 2.17.

1.6[Reserved].

Section 21.[RESERVED].

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Section 22.REPRESENTATIONS AND WARRANTIES

To induce the Administrative Agent and the Lenders to enter into this Agreement and to make the Loans, the Borrower hereby represents and warrants to the Administrative Agent and each Lender, on the Effective Date, that:

1.1Financial Condition. (a) The audited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as of December 31, 2020, and the related consolidated statements of income and cash flows for the fiscal year ended on such date, reported on by Deloitte & Touche LLP, and (b) the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as of March 31, 2021, and the related consolidated statements of income and cash flows for the portion of the fiscal year ended on such date, each delivered to the Administrative Agent prior to the Amendment No. 1 Effective Date, in each case, (i) were prepared in accordance with GAAP consistently applied throughout the periods covered thereby, except as otherwise expressly noted therein, and (ii) present fairly in all material respects the consolidated financial condition of the Borrower and its consolidated Subsidiaries as of such date, and its consolidated income and its consolidated cash flows for the respective fiscal year or portion of the fiscal year then ended, subject, in the case of the financial statements referred to in clause (b), to the absence of footnotes and to normal year-end audit adjustments.

1.2No Change. Since December 31, 2020, no Specified Material Adverse Effect has occurred.

1.3Existence; Compliance with Law. Each of the Borrower and its Significant Subsidiaries (a) is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization, (b) has the organizational power and organizational authority to own and operate its property, to lease the property it operates as lessee and to conduct the business in which it is currently engaged, (c) is duly qualified as a foreign corporation or other organization and in good standing under the laws of each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification except to the extent that the failure to so qualify could not reasonably be expected to have a Material Adverse Effect and (d) is in compliance with all Requirements of Law except for any Requirements of Law being contested in good faith by appropriate proceedings and except to the extent that the failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

1.4Power; Authorization; Enforceable Obligations. The Borrower has the corporate power and corporate authority to execute and deliver and to perform its obligations under the Loan Documents and to obtain extensions of credit hereunder. The Borrower has taken all necessary corporate action to authorize the execution and delivery of, and performance of its obligations under, the Loan Documents to which it is a party and to authorize the extensions of credit on the terms and conditions of this Agreement. No consent or authorization of, filing with, notice to or other act by or in respect of, any Governmental Authority or any other Person is required in connection with the extensions of credit hereunder or with the execution, delivery, performance, validity or enforceability of this Agreement or any of the Loan Documents, except (i) consents, authorizations, filings and notices which have been obtained or made and are in full force and effect, (ii) any consent, authorization or filing that may be required

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in the future the failure of which to make or obtain could not reasonably be expected to have a Material Adverse Effect and (iii) applicable Requirements of Law (including the approval of the CPUC) prior to foreclosure or other exercise of remedies under the Loan Documents. This Agreement has been, and each other Loan Document upon execution and delivery will be, duly executed and delivered. This Agreement constitutes, and each other Loan Document upon execution will constitute, a legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, except as enforceability may be limited by (x) applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally, laws of general application related to the enforceability of securities secured by real estate and by general equitable principles (whether enforcement is sought by proceedings in equity or at law) and (y) applicable Requirements of Law (including the approval of the CPUC) prior to foreclosure or other exercise of remedies hereunder or under the Loan Documents.

1.5No Legal Bar. The execution and delivery of, and the performance of the obligations under, this Agreement and the other Loan Documents, the borrowing of the Loans hereunder and the use of the proceeds thereof will not violate in any material respect any Requirement of Law or any Contractual Obligation of the Borrower or any of its Significant Subsidiaries and will not result in, or require, the creation or imposition of any Lien on any of their respective properties or revenues pursuant to any Requirement of Law or any such Contractual Obligation (other than the Liens created by the Loan Documents and the FMB Indenture).

1.6Litigation. (a) No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened in writing by or against the Borrower or any of its Significant Subsidiaries or against any of their respective material properties or revenues with respect to any of the Loan Documents.

(b)No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened in writing by or against the Borrower or any of its Significant Subsidiaries or against any of their respective material properties or revenues, except as disclosed in the Specified Exchange Act Filings, that could reasonably be expected to have a Material Adverse Effect.

1.7No Default. No Default or Event of Default has occurred and is continuing.

1.8Taxes. The Borrower and each of its Significant Subsidiaries has filed or caused to be filed all Federal and state returns of income and franchise taxes imposed in lieu of net income taxes and all other material tax returns that are required to be filed and has paid all taxes shown to be due and payable on said returns or with respect to any claims or assessments for taxes made against it or any of its property by any Governmental Authority (other than (i) any amounts the validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable, and (ii) claims which could not reasonably be expected to have a Material Adverse Effect). No material tax Liens have been filed against the Borrower or any of its Significant Subsidiaries other than (A) Liens for taxes

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which are not delinquent or (B) Liens for taxes which are being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable.

1.9Federal Regulations. No part of the proceeds of any Loans hereunder, will be used for “buying” or “carrying” any “margin stock” within the respective meanings of each of the quoted terms under Regulation U as now and from time to time hereafter in effect or for any purpose that violates the provisions of the Regulations of the Federal Reserve Board.

1.10ERISA. No Reportable Event has occurred during the five year period prior to the date on which this representation is made or deemed made with respect to any Plan, and each Plan has complied with the applicable provisions of ERISA and the Code, except, in each case, to the extent that any such Reportable Event or failure to comply with the applicable provisions of ERISA or the Code could not reasonably be expected to result in a Material Adverse Effect. During the five year period prior to the date on which this representation is made or deemed made, there has been no (i) failure to make a required contribution to any Plan that would result in the imposition of a Lien or other encumbrance or the provision of security under Section 430 of the Code or Section 303 or 4068 of ERISA, or the arising of such a Lien or encumbrance; or (ii) “unpaid minimum required contribution” or “accumulated funding deficiency” (as defined or otherwise set forth in Section 4971 of the Code or Part 3 of Subtitle B of Title I of ERISA), whether or not waived, except, in each case, to the extent that such event could not reasonably be expected to result in a Material Adverse Effect. No termination of a Single Employer Plan has occurred, and no Lien in favor of the PBGC or a Plan has arisen, during such five-year period. The present value of all accrued benefits under each Single Employer Plan (based on those assumptions used to fund such Plan) did not, as of the last annual valuation date for which a certified actuarial valuation report is available prior to the date on which this representation is made or deemed made, exceed the value of the assets of such Plan allocable to such accrued benefits, except as could not reasonably be expected to result in a Material Adverse Effect. Neither the Borrower nor any Commonly Controlled Entity has had a complete or partial withdrawal from any Multiemployer Plan during the five year period prior to the date on which this representation is made or deemed made that has resulted or could reasonably be expected to result in a material liability under ERISA, and neither the Borrower nor any Commonly Controlled Entity would become subject to any liability under ERISA if the Borrower or any such Commonly Controlled Entity were to withdraw completely from all Multiemployer Plans as of the valuation date most closely preceding the date on which this representation is made or deemed made, except as could not reasonably be expected to result in a Material Adverse Effect. No such Multiemployer Plan is in endangered or critical status (within the meaning of Section 305 of ERISA) or in Insolvency.

1.11Investment Company Act; Other Regulations. The Borrower is not an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended. On the Effective Date, the Borrower is not subject to regulation under any Requirement of Law (other than (a) Regulation X of the Federal Reserve Board and (b) Sections 817-830, and Sections 701 and 851 of the California Public Utilities Code) that limits its ability to incur Indebtedness under this Agreement.

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1.12Use of Proceeds. The proceeds of the Loans shall be used to fund the transactions contemplated under the Plan of Reorganization.

1.13Environmental Matters. Except as disclosed in the Specified Exchange Act Filings, the Borrower and its Significant Subsidiaries are not subject to any pending violations or liabilities under Environmental Laws or relating to the disposal, spill or other release of Materials of Environmental Concern that would reasonably be expected to have a Material Adverse Effect, and, to the knowledge of the Borrower, there are no facts, circumstances or conditions that could reasonably be expected to give rise to such violations or liabilities.

1.14Regulatory Matters. Solely by virtue of the execution, delivery and performance of, or the consummation of the transactions contemplated by this Agreement, no Lender shall be or become subject to regulation (a) under the FPA or (b) as a “public utility” or “public service corporation” or the equivalent under any Requirement of Law.

1.15Sanctions; Anti-Corruption. None of the Borrower, any of its Subsidiaries, nor, to the knowledge of the Borrower, any director, officer, agent, Affiliate or employee of the Borrower or any of its Subsidiaries is currently (i) the subject of any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department or the U.S. State Department (“Sanctions”) or (ii) located, organized or resident in a country or territory that is, or whose government is, the subject of any Sanctions. None of the Borrower, any of its Subsidiaries nor, to the knowledge of the Borrower, any director, officer, agent, Affiliate or employee of the Borrower or any of its Subsidiaries, has taken any action, directly or indirectly, that would result in a violation in any material respect by any such Person of the United States Foreign Corrupt Practices Act of 1977, as amended (“FCPA”) or of any other anti-bribery or anti-corruption laws, rules, regulations legally applicable to such Persons (collectively, “Anti-Corruption Laws”). The Borrower will not use the proceeds of the Loans, or lend, contribute or otherwise make available such proceeds (a) to any Subsidiary, Affiliate, joint venture partner or other Person or entity, to fund the activities of any Person, or in any country or territory, that, at the time of such funding, is, or whose government is, the subject of any Sanctions, or (a) directly, or, to the knowledge of the Borrower, indirectly, for any payments to any governmental official or employee, political party, official of a political party, candidate for political office, or anyone else acting in an official capacity, in order to obtain, retain or direct business or obtain any improper advantage, in violation of the FCPA or of any Anti-Corruption Laws.

1.16Affected Financial Institutions. The Borrower is not an Affected Financial Institution.

1.17Solvency. The Borrower and its Subsidiaries, on a consolidated basis, are Solvent as of the Amendment No. 1 Effective Date.

1.18Disclosure.

(a)All written information relating to the Borrower, its Subsidiaries and their respective businesses, other than any projections, estimates and other forward-looking materials and information of a general economic or industry specific nature, that has been provided by or on behalf of the Borrower to the

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Administrative Agent or the Lenders in connection with the transactions contemplated hereby does not, when taken as a whole, contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements contained therein not materially misleading in light of the circumstances under which such statements were made (giving effect to all supplements and updates thereto). Any projected information, estimates, other forward-looking materials and pro forma financial information that have been made available to any Lenders or the Administrative Agent prior to the Effective Date in connection with the transactions contemplated hereby have been prepared in good faith based upon assumptions believed by the Borrower to be reasonable as of the date such information was furnished to the Lenders and as of the Effective Date (it being understood that actual results may vary materially from such projections and pro forma information and such projections and pro forma information are not a guarantee of performance).

(b)As of the Effective Date, to the knowledge of the Borrower, the information included in any Beneficial Ownership Certification provided on or prior to the Effective Date to any Lender in connection with this Agreement is true and correct in all respects.

1.19Status of Obligations. The issuance to the Administrative Agent of the Senior Bonds provides the Lenders, as beneficial holders of the Senior Bonds through the Administrative Agent, the benefit of the Lien of the FMB Indenture equally and ratably with the holders of other First Mortgage Bonds.

1.20Ownership of Property. As of the Effective Date, each of the Borrower and its Significant Subsidiaries has good title to, or valid leasehold interests in, all its real and personal property material to its business, subject to no Liens other than Liens permitted under Section 7.3, except for where the failure would not, individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

1.21Covered Entity. The Borrower is not a Covered Entity.

Section 23.CONDITIONS PRECEDENT

1.1Conditions to the Effective Date. The occurrence of the Effective Date and the obligation of each Lender to make its Loans hereunder on the Effective Date is subject to the satisfaction of the following conditions precedent:

(a)Credit Agreement. The Administrative Agent shall have received this Agreement (including copies of all schedules attached hereto in a form reasonably satisfactory to the Lenders), executed and delivered by the Administrative Agent, the Borrower and each Person listed on Schedule 1.1.

(b)Consents and Approvals. All governmental and third party consents and approvals necessary in connection with the execution and delivery of this Agreement and the other Loan Documents and the consummation of the transactions contemplated hereby shall have been obtained and be in full force and effect; and the Administrative Agent shall have received a certificate of a Responsible Officer to the foregoing effect.

(c)KYC Information. At least three (3) Business Days prior to the Effective Date, the Administrative Agent and each Lender shall have received

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all documentation and information relating to the Borrower as is reasonably requested in writing by the Administrative Agent and/or any such Lender at least ten (10) Business Days prior to the Effective Date that is required by Governmental Authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation. If the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation and the Administrative Agent or any Lender so request at least five (5) Business Days prior to the Effective Date, then at least three (3) Business Days prior to the Effective Date, the Borrower shall have delivered to the Administrative Agent and/or any such Lender a Beneficial Ownership Certification in relation to the Borrower.

(d)Bond Documents. The Administrative Agent shall have received:

Section 24.the Bond Delivery Agreement, duly executed and delivered by the Borrower and Administrative Agent;

Section 25.the Senior Bonds in a face amount equal to the Loans as of the Effective Date, duly issued and authenticated under the FMB Indenture and in a form reasonably satisfactory to the Administrative Agent;

Section 26.the Supplemental Indenture, duly executed and delivered by the Borrower and the Indenture Trustee and in a form reasonably satisfactory to the Administrative Agent;

Section 27.a certificate of a duly authorized officer of the Indenture Trustee certifying that each Senior Bond has been authenticated and is outstanding under the FMB Indenture;

Section 28.copies of all legal opinions and other documents delivered to the Indenture Trustee by or on behalf of the Borrower on or prior to the Effective Date in connection with the issuance of each Senior Bond; and

Section 29.copies of all title reports and commitments as of the Effective Date with respect to the Mortgaged Property consisting of real property as to which Liens in favor of the Indenture Trustee, for the benefit of the holders of the First Mortgage Bond, has been granted.

(a)Fees. The Lenders, the Arrangers and the Administrative Agent shall have received all fees required to be paid, and all expenses for which invoices have been presented (including the reasonable fees and expenses of legal counsel) on or before the date that is two (2) Business Days prior to the Effective Date.

(b)Closing Certificate; Certified Articles of Incorporation; Good Standing Certificates. The Administrative Agent shall have received (i) a certificate of the Borrower, dated the Effective Date, substantially in the form of Exhibit D, with appropriate insertions and attachments, including the articles of incorporation of the Borrower certified as of a recent date by the Secretary of State of the State of California, (ii) a good standing certificate for the Borrower dated as of a recent date from the Secretary of State of the State of California, and (iii) a certificate of a Responsible Officer, dated the Effective Date, confirming the satisfaction of the conditions precedent set forth in Sections 5.1(h) and (i).

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(c)Legal Opinion. The Administrative Agent shall have received the legal opinion of (i) Hunton Andrews Kurth LLP, counsel to the Borrower, and (ii) Munger, Tolles & Olson LLP, special California regulatory counsel to the Borrower, each in a form reasonably satisfactory to the Administrative Agent.

(d)Representations and Warranties. Each of the representations and warranties made by the Borrower in this Agreement that does not contain a materiality qualification shall be true and correct in all material respects on and as of the Effective Date, and each of the representations and warranties made by the Borrower in this Agreement that contains a materiality qualification shall be true and correct on and as of the Effective Date (or, in each case, to the extent such representations and warranties specifically relate to an earlier date, that such representations and warranties were true and correct in all material respects, or true and correct, as the case may be, as of such earlier date).

(e)No Default. No Default or Event of Default shall have occurred and be continuing on the Effective Date or would result from the funding of the Loans on the Effective Date.

(f)Notice of Borrowing. The Administrative Agent shall have received a notice of borrowing in accordance with the requirements of Section 2.2.

(g)Solvency. The Administrative Agent shall have received a solvency certificate from the chief financial officer of the Borrower in substantially the form of Exhibit I hereto.

Section 30.AFFIRMATIVE COVENANTS

The Borrower hereby agrees that, so long as any Loan, any interest on any Loan or any fee payable to any Lender or the Administrative Agent hereunder remains outstanding, or any other amount then due and payable is owing to any Lender or the Administrative Agent hereunder, the Borrower shall and, with respect to Sections 6.3 and 6.6(b), shall cause its Significant Subsidiaries to:

1.1Financial Statements. Furnish to the Administrative Agent with a copy for each Lender, and the Administrative Agent shall deliver to each Lender:

(a)as soon as available, but in any event within 120 days after the end of each fiscal year of the Borrower, a copy of the audited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such year and the related audited consolidated statements of income and cash flows for such year, setting forth in each case in comparative form the figures for the previous year, reported on without a “going concern” or like qualification or exception, or qualification arising out of the scope of the audit, by Deloitte & Touche LLP or other independent certified public accountants of nationally recognized standing; and

(b)as soon as available, but in any event not later than 60 days after the end of each of the first three quarterly periods of each fiscal year of the Borrower, the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as at the end of such quarter and the related unaudited consolidated statements of income and cash flows for such quarter and the portion of the fiscal year through the end of such quarter, setting forth

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in each case in comparative form the figures for the previous year, certified by a Responsible Officer as being fairly stated in all material respects (subject to the absence of footnotes and normal year-end audit adjustments).

All such financial statements shall (x) be complete and correct in all material respects and (y) shall be prepared in reasonable detail and in accordance with GAAP applied (except as approved by such accountants or officer, as the case may be, and disclosed in reasonable detail therein) consistently throughout the periods reflected therein and with prior periods, subject, in each case to the absence of footnotes and to normal year-end audit adjustments. The Borrower shall be deemed to have delivered the financial statements required to be delivered pursuant to this Section 6.1 upon the filing of such financial statements by the Borrower through the SEC’s EDGAR system (or any successor electronic gathering system that is publicly available free of charge) or the publication by the Borrower of such financial statements on its website.

1.2Certificates; Other Information. Furnish to the Administrative Agent, for delivery to the Lenders:

(a)within two Business Days after the delivery of any financial statements pursuant to Section 6.1, (i) a certificate of a Responsible Officer stating that such Responsible Officer has obtained no actual knowledge of any Default or Event of Default except as specified in such certificate and (ii) a Compliance Certificate, substantially in the form of Exhibit C, containing all information and calculations reasonably necessary for determining compliance by the Borrower with the provisions of this Agreement referred to therein as of the last day of the fiscal quarter or fiscal year of the Borrower, as the case may be;

(b)within five days after the same are sent, copies of all financial statements and reports that the Borrower sends to the holders of any class of its debt securities or public equity securities, provided that, such financial statements and reports shall be deemed to have been delivered upon the filing of such financial statements and reports by the Borrower through the SEC’s EDGAR system (or any successor electronic gathering system that is publicly available free of charge) or publication by the Borrower of such financial statements and reports on its website;

(c)promptly, such additional financial and other information (other than any such information the disclosure of which is prohibited by applicable law or binding agreement or subject to attorney-client privilege or constitutes attorney-work product or constitutes non-financial trade secrets or non-financial proprietary information so long as (x) such confidentiality obligation was not entered into in contemplation hereof and (y) the Borrower provides such Lender with notice that information is being withheld due to the existence of such confidentiality obligation) as any Lender, through the Administrative Agent, may from time to time reasonably request; and

(d)promptly, such documentation and other information that the Administrative Agent or such Lender reasonably requests in order to comply with its ongoing obligations under applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation.

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1.3Payment of Taxes. Pay all taxes due and payable or any other tax assessments made against the Borrower or any of its Significant Subsidiaries or any of their respective property by any Governmental Authority (other than (i) any amounts the validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of the Borrower or any of its Significant Subsidiaries, as applicable or (ii) where the failure to effect such payment could not reasonably be expected to have a Material Adverse Effect).

1.4Maintenance of Existence; Compliance. (a)(i) Preserve, renew and keep in full force and effect its organizational existence and (ii) take all reasonable action to maintain all rights, privileges and franchises necessary or desirable in the normal conduct of its business, except, in each case, as otherwise permitted by Section 7.4 and except, in the case of clause (ii) above, to the extent that failure to do so could not reasonably be expected to have a Material Adverse Effect; (b) comply with all Contractual Obligations except to the extent that failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect and (c) comply with all Requirements of Law except for any Requirements of Law being contested in good faith by appropriate proceedings or except to the extent that failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

1.5Maintenance of Property; Insurance. (a) Keep all property useful and necessary in its business in good working order and condition, ordinary wear and tear and casualty excepted, except to the extent that failure to do so could not, in the aggregate, reasonably be expected to have a Material Adverse Effect, and (b) maintain with financially sound and reputable insurance companies insurance on all its material property in at least such amounts and against at least such risks as are usually insured against in the same general area by companies engaged in the same or a similar business of comparable size and financial strength and owning similar properties in the same general areas in which the Borrower operates, which may include self-insurance, if determined by the Borrower to be reasonably prudent.

1.6Inspection of Property; Books and Records; Discussions. (a) Keep proper books of records and account in which full, true and correct entries in conformity with GAAP and all Requirements of Law shall be made of all dealings and transactions in relation to its business and activities and (b) unless a Default or Event of Default has occurred and is continuing, not more than once a year and after at least five Business Days’ notice, (i) permit representatives of any Lender to visit and inspect any of its properties and examine and make abstracts from any of its books and records at any reasonable time to discuss the business, operations, properties and financial and other condition of the Borrower and its Significant Subsidiaries with officers and employees of the Borrower and its Significant Subsidiaries and (ii) use commercially reasonable efforts to provide for the Lenders (in the presence of representatives of the Borrower) to meet with the independent certified public accountants of the Borrower and its Significant Subsidiaries; provided, that any such visits or inspections shall be subject to such conditions as the Borrower and each of its Significant Subsidiaries shall deem necessary based on reasonable considerations of safety, security and confidentiality; and provided, further, that neither the Borrower nor any Significant Subsidiary shall be required to disclose to any Person any information the disclosure of which is prohibited by applicable law or binding agreement or subject to attorney-client privilege or constitutes attorney-work product or

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constitutes non-financial trade secrets or non-financial proprietary information so long as (x) such confidentiality obligation was not entered into in contemplation hereof and (y) the Borrower provides such Lender with notice that information is being withheld due to the existence of such confidentiality obligation.

1.7Notices. Give notice to the Administrative Agent, and the Administrative Agent shall deliver such notice to each Lender, promptly upon any Responsible Officer obtaining knowledge of:

(a)the occurrence of any Default or Event of Default;

(b)any change in the Rating issued by either S&P or Moody’s; and

(c)the occurrence of an ERISA Event which, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect (provided, that, any judicial proceeding instituted by PBGC that, within 60 days after the institution of such proceeding, has been withdrawn or stayed by PBGC or otherwise, shall be disregarded for the purpose of this Section 6.7(c)).

1.8Maintenance of Licenses, etc. Maintain in full force and effect any authorization, consent, license or approval of any Governmental Authority necessary for the conduct of the Borrower’s business as now conducted by it or necessary in connection with this Agreement, except to the extent the failure to do so could not reasonably be expected to have a Material Adverse Effect.

1.9Further Assurances.

(a)(i) Comply with Section 7.08(a) of the FMB Indenture, (ii) deliver to the Administrative Agent within 120 days after the Effective Date, a copy of the Opinion of Counsel (as defined in the FMB Indenture) delivered to the Indenture Trustee under Section 7.08(a)(i) of the FMB Indenture relating the Supplemental Indenture and (iii) deliver to the Administrative Agent a copy of each Opinion of Counsel delivered to the Indenture Trustee under Section 7.08(a)(ii) of the FMB Indenture relating to the Supplemental Indenture.

(b)Promptly upon the reasonable request by the Administrative Agent, or by the Required Lenders through the Administrative Agent, (i) correct any material defect or error that may be discovered in any Loan Document or the execution, acknowledgment, filing or recordation thereof and (ii) do, execute, acknowledge and deliver any and all such further certificates, documents, agreements and other instruments as reasonably required from time to time to carry out more effectively the purposes of the Loan Documents.

1.10Use of Proceeds. The Borrower shall use the proceeds of the Loans in accordance with Section 4.12.

Section 31.NEGATIVE COVENANTS

The Borrower hereby agrees that, so long as any Loan, or any interest on any Loan or any fee payable to any Lender or the Administrative Agent hereunder remains outstanding, or any other amount then due and payable is owing to any Lender or the Administrative Agent hereunder, the Borrower shall not and shall not permit its Significant Subsidiaries to:

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1.1Indebtedness. At all times prior to the Indebtedness Covenant Release Date, create, incur, assume or permit to exist any Indebtedness, except for:

(a)Indebtedness and other Obligations created hereunder;

(b)Indebtedness of the Borrower under the Utility Revolving Credit Agreement in an aggregate outstanding principal amount not to exceed $3,500,000,000 plus any additional amounts permitted to be incurred thereunder pursuant to Section 2.3 of the Utility Revolving Credit Agreement as in effect on the date hereof and any Permitted Refinancing thereof;

(c)Indebtedness of the Borrower outstanding on the Effective Date in an aggregate outstanding principal amount not to exceed, together with any Loans outstanding hereunder on the Effective Date, $33,350,000,000 and any Permitted Refinancing thereof;

(d)Indebtedness (i) pursuant to tenders, statutory obligations, bids, leases, governmental contracts, trade contracts, surety, stay, customs, appeal, performance and/or return of money bonds or other similar obligations incurred in the ordinary course of business and (ii) in respect of letters of credit, bank guaranties, surety bonds, performance bonds or similar instruments and reimbursement obligations to support any of the foregoing items;

(e)(i) Guarantee Obligations with respect to the obligations of suppliers, customers and licensees and other third parties in the ordinary course of business, (ii) Indebtedness incurred in the ordinary course of business to pay the deferred purchase price of goods or services or progress payments in connection with such goods and services and (iii) Indebtedness in respect of letters of credit, bankers’ acceptances, bank guaranties or similar instruments supporting trade payables, warehouse receipts or similar facilities entered into in the ordinary course of business, workers compensation claims or other employee benefits;

(f)Guarantee Obligations with respect to Indebtedness otherwise permitted to be incurred pursuant to this Section 7.1 and Guarantee Obligations with respect to the obligations of Subsidiaries and joint ventures of the Borrower; provided that no such Guarantee Obligations with respect to Indebtedness of the Borrower constituting debt for borrowed money or evidenced by notes, bonds, debentures or other similar instruments (including, for the avoidance of doubt, the First Mortgage Bonds) shall be permitted except to the extent provided by a Person that is, or concurrently with providing such Guarantee Obligations becomes, a guarantor of the Obligations hereunder on terms and pursuant to documentation reasonably satisfactory to the Administrative Agent;

(g)Indebtedness consisting of (i) the financing of insurance premiums and/or (ii) take-or-pay obligations contained in supply arrangements;

(h)Indebtedness with respect to Capital Lease Obligations and purchase money Indebtedness; provided, that the aggregate outstanding principal amount of Indebtedness with respect to Capital Lease Obligations shall not exceed $500,000,000 at any one time;

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(i)(i) obligations under any Cash Management Agreement and (ii) Indebtedness under any Swap Agreement permitted under Section 7.6;

(j)Indebtedness arising from any agreement providing for indemnification, adjustment or purchase price or similar obligations (including contingent earn-out obligations) incurred in connection with any Disposition or any purchase of assets or Capital Stock, and Indebtedness arising from guaranties, letters of credit, bank guaranties, surety bonds, performance bonds or similar instruments securing the performance of the Borrower or its Subsidiaries pursuant to any such agreement;

(k)Indebtedness in respect of banking services and incentive, supplier finance or similar programs incurred in the ordinary course of business;

(l)customer deposits and advance payments received in the ordinary course of business from customers for goods and services purchased in the ordinary course of business;

(m)Indebtedness representing deferred compensation to employees, consultants or independent contractors incurred in the ordinary course of business;

(n)Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or other similar instrument drawn against insufficient funds in the ordinary course of business;

(o)endorsements for collection or deposit in the ordinary course of business;

(p)Indebtedness issued or incurred to fund rate base growth in an aggregate outstanding principal amount not to exceed $9,000,000,000 at any time and any Permitted Refinancing thereof; and

(q)other Indebtedness of the Borrower in an aggregate outstanding principal amount not to exceed the excess, if any, of 10% of Net Tangible Assets of the Borrower over the amount of Indebtedness incurred pursuant to clause (p) above.

Notwithstanding anything herein to the contrary, no Guarantee Obligations from any Significant Subsidiary of the Borrower with respect to Indebtedness of the Borrower constituting debt for borrowed money or evidenced by notes, bonds, debentures or other similar instruments (including, for the avoidance of doubt, the First Mortgage Bonds) shall be permitted hereunder except to the extent provided by a Person that is, or concurrently with providing such Guarantee Obligations becomes, a guarantor of the Obligations hereunder on terms and pursuant to documentation reasonably satisfactory to the Administrative Agent.

1.2Consolidated Capitalization Ratio. Permit the Consolidated Capitalization Ratio on the last day of any fiscal quarter, from and after the last day of the first fiscal quarter ending after the Effective Date, to exceed 0.65 to 1.00.

1.3Liens. Create, incur, assume or suffer to exist any Lien upon any assets of the Borrower or any Significant Subsidiary, whether now owned or

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hereafter acquired, except for (a) Liens securing the Obligations under this Agreement and the other Loan Documents and (b) Liens permitted under Section 7.06(b) of the FMB Indenture.

1.4Fundamental Changes. Enter into any merger, consolidation or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or Dispose of all or substantially all of its property or business (including, without limitation, rental equipment or leasehold interests and excluding the sale or transfer of any accounts receivable or of any amounts that are accrued and recorded in a regulatory account for collections by the Borrower, in each case, in connection with a securitization transaction including, without limitation, any A/R Securitization Transaction), except that the Borrower may be merged, consolidated or amalgamated with another Person or Dispose of all or substantially all of its property or business so long as, after giving effect to such transaction, (a) no Default or Event of Default shall have occurred and be continuing, (b) either (i) the Borrower is the continuing or surviving corporation of such merger, consolidation or amalgamation or (ii) the continuing or surviving corporation of such merger, consolidation or amalgamation, if not the Borrower or the purchaser, (x) shall be an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia, (y) shall have assumed all obligations of the Borrower under the Loan Documents pursuant to arrangements reasonably satisfactory to the Administrative Agent and (z) to the extent requested by the Administrative Agent or any Lender, shall have promptly provided to the Administrative Agent or such Lender all documentation and other information that may be required by the Administrative Agent or such Lender in order to enable compliance with applicable “know-your-customer” and anti-money laundering rules and regulations, including information required by the Patriot Act and the Beneficial Ownership Regulation and (c) the ratings by Moody’s and S&P of the continuing or surviving corporation’s or purchaser’s senior, secured debt shall be at least the higher of (1) Baa3 from Moody’s and BBB- from S&P and (2) the ratings by such rating agencies of the Borrower’s senior, secured debt in effect before the earlier of the occurrence or the public announcement of such event.

1.5Sale and Lease Back Transactions. Enter into any arrangement, directly or indirectly, with any Person whereby it shall sell or transfer any property having fair market value in excess of $10,000,000, real or personal, used or useful in its business, whether now owned or hereafter acquired, and thereafter rent or lease such property or other property that it intends to use for substantially the same purpose or purposes as the property being sold or transferred, except for (a) those transactions described on Schedule 7.5 and (b) any other sale of any fixed or capital assets that is made for cash consideration; provided that, in each case, if such sale and leaseback results in a Capital Lease Obligation, such Capital Lease Obligation is permitted by Section 7.1 and any Lien made the subject of such Capital Lease Obligation is permitted by Section 7.3.

1.6Swap Agreements. Enter into any Swap Agreement, other than Swap Agreements entered into not for speculative purposes (a) to hedge or mitigate risks to which the Borrower and its Subsidiaries are exposed in the conduct of its business or the management of its liabilities (including, without limitation, raw material, commodities, fuel, electricity or other supply costs and currency risks), (b) to effectively cap, collar or exchange interest rates (from fixed to floating rates, from one floating rate to another floating rate or fixed rate or otherwise) with respect to any interest bearing Indebtedness of the Borrower and

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its Subsidiaries permitted by this Agreement, (c) to swap currency in connection with funding the business of the Borrower and its Subsidiaries in the ordinary course of business or (d) entered into in connection with any A/R Securitization Transaction.

1.7Amendments to FMB Indenture. Amend, supplement, modify or waive the FMB Indenture in any manner that is materially adverse to the Lenders hereunder; provided that the foregoing shall not prohibit the Borrower from supplementing the FMB Indenture in order to provide for the issuance of additional First Mortgage Bonds in accordance with the FMB Indenture or to add property to the Lien of the FMB Indenture.

Section 32.EVENTS OF DEFAULT

If any of the following events shall occur and be continuing on or after the Effective Date:

(a)the Borrower shall fail to pay any principal of the Loans when due in accordance with the terms hereof; or the Borrower shall fail to pay any interest on the Loans, or any other amount payable hereunder or under any other Loan Document, within five Business Days after any such interest or other amount becomes due in accordance with the terms hereof; or

(b)any representation or warranty made or deemed made by the Borrower herein or in any other Loan Document or that is contained in any certificate, document or financial or other statement furnished by it at any time under or in connection with this Agreement or any such other Loan Document shall prove to have been inaccurate in any material respect on or as of the date made or deemed made, unless, as of any date of determination, the facts or circumstances to which such representation or warranty relates have changed with the result that such representation or warranty is true and correct in all material respects on such date; or

(c)the Borrower shall default in the observance or performance of any agreement contained in Section 6.4(a)(i), Section 6.7(a), Section 6.10, Section 7.1, Section 7.2, Section 7.3 or Section 7.4 of this Agreement; or

(d)the Borrower shall default in the observance or performance of any other agreement contained in this Agreement or any other Loan Document (other than as provided in paragraphs (a) through (c) of this Section), and such default shall continue unremedied for a period of 30 days after notice to the Borrower from the Administrative Agent at the request of the Required Lenders; or

(e)the Borrower or any of its Significant Subsidiaries shall (i) default in making any payment of any principal of any Indebtedness (including any Guarantee Obligation, but excluding the Loans) on the due date with respect thereto (after giving effect to any period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created); or (ii) default in making any payment of any interest on any such Indebtedness beyond the period of grace, if any, provided in the instrument or agreement under which such Indebtedness was created; or (iii) default in the observance or performance of any other agreement or condition relating to any such Indebtedness or contained in any instrument or agreement evidencing, securing

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or relating thereto, or any other event shall occur or condition exist, the effect of which default or other event or condition is to cause, or (in the case of all Indebtedness other than Indebtedness under any Swap Agreement) to permit the holder or beneficiary of such Indebtedness (or a trustee or agent on behalf of such holder or beneficiary) to cause, with the giving of notice if required, such Indebtedness to become due prior to its stated maturity or (in the case of any such Indebtedness constituting a Guarantee Obligation) to become payable; provided, that a default, event or condition described in clause (i), (ii) or (iii) of this paragraph (e) shall not at any time constitute an Event of Default unless, at such time, one or more defaults, events or conditions of the type described in clauses (i), (ii) and (iii) of this paragraph (e) shall have occurred and be continuing with respect to Indebtedness the outstanding principal amount of which exceeds in the aggregate $200,000,000; provided, further, that unless payment of the Loans hereunder has already been accelerated, if such default shall be cured by the Borrower or such Significant Subsidiary or waived by the holders of such Indebtedness and any acceleration of maturity having resulted from such default shall be rescinded or annulled, in each case, in accordance with the terms of such agreement or instrument, without any modification of the terms of such Indebtedness requiring the Borrower or such Significant Subsidiary to furnish security or additional security therefor, reducing the average life to maturity thereof or increasing the principal amount thereof, or any agreement by the Borrower or such Significant Subsidiary to furnish security or additional security therefor or to issue in lieu thereof Indebtedness secured by additional or other collateral or with a shorter average life to maturity or in a greater principal amount, then any Default hereunder by reason thereof shall be deemed likewise to have been thereupon cured or waived; or

(f)(i) the Borrower or any of its Significant Subsidiaries shall commence any case, proceeding or other action (A) under any existing or future law of any jurisdiction, domestic or foreign, relating to bankruptcy, insolvency, reorganization or relief of debtors, seeking to have an order for relief entered with respect to it, or seeking to adjudicate it as bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding up, liquidation, dissolution, composition or other relief with respect to it or its debts, or (B) seeking appointment of a receiver, trustee, custodian, conservator or other similar official for it or for all or any substantial part of its assets, or the Borrower or any of its Significant Subsidiaries shall make a general assignment for the benefit of its creditors; or (ii) there shall be commenced against the Borrower or any of its Significant Subsidiaries any case, proceeding or other action of a nature referred to in clause (i) above that (A) results in the entry of an order for relief or any such adjudication or appointment or (B) remains undismissed, undischarged or unbonded for a period of 60 days; or (iii) there shall be commenced against the Borrower or any of its Significant Subsidiaries any case, proceeding or other action seeking issuance of a warrant of attachment, execution, distraint or similar process against all or any substantial part of its assets that results in the entry of an order for any such relief that shall not have been vacated, discharged, or stayed or bonded pending appeal within 60 days from the entry thereof; or (iv) the Borrower or any of its Significant Subsidiaries shall generally not, or shall be unable to, or shall admit in writing its inability to, pay its debts as they become due; or

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(g)there occurs any ERISA Event that, individually or in the aggregate, would reasonably be expected to result in a Material Adverse Effect; or

(h)one or more judgments or decrees shall be entered against the Borrower or any of its Significant Subsidiaries by a court of competent jurisdiction involving in the aggregate a liability (not paid or, subject to customary deductibles, fully covered by insurance as to which the relevant insurance company has not denied coverage) of $200,000,000 or more, and all such judgments or decrees shall not have been vacated, discharged, stayed or bonded pending appeal within 45 days from the entry thereof unless, in the case of a discharge, such judgment or decree is due at a later date in one or more payments and the Borrower or such Significant Subsidiary satisfies the obligation to make such payment or payments on or prior to the date such payment or payments become due in accordance with such judgment or decree; or

(i)there shall have occurred a Change of Control; or

(j)any Loan Document, at any time after its execution and delivery and for any reason other than as expressly permitted hereunder or thereunder or satisfaction in full of all the Obligations, ceases to be in full force and effect; or the Borrower contests in any manner in writing the validity or enforceability of any Loan Document; or the Borrower denies in writing that it has any or further liability or obligation under any Loan Document, or purports in writing to revoke, terminate or rescind any Loan Document; or

(k)at any time (i) any Senior Bond shall cease to be outstanding for any reason other than (A) the payment in full of the applicable Tranche relating to such Senior Bond and other obligations then due and owing under the Loan Documents with respect thereto or (B) the payment in full of such Senior Bond, (ii) the Administrative Agent, on behalf of the Lenders, shall cease at any time to be the holder of any Senior Bond for all purposes of the FMB Indenture (unless such Senior Bond is transferred by the Administrative Agent other than in connection with the payment in full of the obligations with respect to such Senior Bond) or (iii) the Lien of the FMB Indenture shall cease to constitute a valid and enforceable Lien on the Mortgaged Property;

then, and in any such event, (A) if such event is an Event of Default specified in clause (i) or (ii) of paragraph (f) above with respect to the Borrower, the Loans (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents shall immediately become due and payable, and (B) if such event is any other Event of Default, either or both of the following actions may be taken: with the consent of the Required Lenders, the Administrative Agent may, or upon the request of the Required Lenders, the Administrative Agent shall, by notice to the Borrower, declare the Loans (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents to be due and payable forthwith, whereupon the same shall immediately become due and payable. Except as expressly provided above in this Section, presentment, demand, protest and all other notices of any kind are hereby expressly waived by the Borrower.

Section 33.THE AGENTS

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1.1Appointment and Authority. Each of the Lenders hereby irrevocably appoints JPMorgan Chase Bank, N.A. to act on its behalf as the Administrative Agent hereunder and under the other Loan Documents and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. The provisions of this Section 9 are solely for the benefit of the Agents, the Lenders and the Borrower shall not have rights as a third-party beneficiary of any of such provisions (other than with respect to the Borrower’s rights under Sections 9.9(a) and (b)). It is understood and agreed that the use of the term “agent” herein or in any other Loan Documents (or any other similar term) with reference to any Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law. Instead such term is used as a matter of market custom, and is intended to create or reflect only an administrative relationship between contracting parties.

1.2Delegation of Duties. The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub-agents appointed by it. The Administrative Agent, and any such sub-agent may each perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Section shall apply to any such sub-agent and to the Related Parties of the Administrative Agent, and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent. The Administrative Agent shall not be responsible for the negligence or misconduct of any sub-agents except to the extent that a court of competent jurisdiction determines in a final and nonappealable judgment that the Administrative Agent acted with gross negligence or willful misconduct in the selection of such sub-agents.

1.3Exculpatory Provisions.

(a)No Agent shall have any duties or obligations except those expressly set forth herein and in the other Loan Documents, and its duties hereunder shall be administrative in nature. Without limiting the generality of the foregoing, no Agent:

Section 34.shall be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;

Section 35.shall have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that an Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein or in the other Loan Documents); provided that no Agent shall be required to take any action that, in its opinion or the opinion of its counsel, may expose such Agent to liability or that is contrary to any Loan Document or applicable law, including for the avoidance of doubt any action that may be in violation of the automatic stay under any Debtor Relief Law or that may effect a forfeiture, modification or termination of property of a Defaulting Lender in violation of any Debtor Relief Law; and

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Section 36.shall, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as an Agent or any of its Affiliates in any capacity.

(a)No Agent shall be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as such Agent shall believe in good faith shall be necessary, under the circumstances as provided in Sections 10.1 and 8), or (ii) in the absence of its own gross negligence or willful misconduct as determined by a court of competent jurisdiction by final and nonappealable judgment.

(b)No Agent shall be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default or Event of Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Section 5 or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to such Agent.

1.2Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, Internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of a Loan, that by its terms must be fulfilled to the satisfaction of a Lender, the Administrative Agent may presume that such condition is satisfactory to such Lender unless the Administrative Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

1.3Notice of Default. The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default unless the Administrative Agent has received notice from a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Required Lenders (or, if so specified by this Agreement, all Lenders); provided that unless and until such Agent shall have received such directions,

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such Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders.

1.4Non-Reliance on Agents and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the business, operations, property, condition (financial or otherwise), prospects or creditworthiness of the Borrower or any of its Affiliates that may come into the possession of such Agent or any of its officers, directors, employees, agents, attorneys in fact or Affiliates.

1.5Indemnification. The Lenders agree to indemnify each Agent in its capacity as such (to the extent not reimbursed by the Borrower and without limiting the obligation of the Borrower to do so), ratably according to their respective Percentages in effect on the date on which indemnification is sought under this Section (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with such Percentages immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time (whether before or after the payment of the Loans) be imposed on, incurred by or asserted against such Agent in any way relating to or arising out of, the Commitments, this Agreement, any of the other Loan Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by such Agent under or in connection with any of the foregoing; provided that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements that are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from such Agent’s gross negligence or willful misconduct.

1.6Agent in Its Individual Capacity. Each Person serving as an Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Agent, and the terms “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include such Person serving as an Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, own securities of, act as the financial advisor or in any other advisory capacity for, and generally engage in any kind of business with, the Borrower or any Subsidiary or other Affiliate thereof as if such Person were not an Agent hereunder and without any duty to account therefor to the Lenders.

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1.7Successor Agents.

(a)The Administrative Agent may resign upon 10 days’ notice to the Lenders and the Borrower. If the Administrative Agent shall so resign under this Agreement and the other Loan Documents, then the Required Lenders shall appoint from among the Lenders a successor agent for the Lenders, which successor agent shall (unless an Event of Default under Section 8(f) with respect to the Borrower shall have occurred and be continuing) be subject to approval by the Borrower (which approval shall not be unreasonably withheld, conditioned or delayed), whereupon such successor agent shall succeed to the rights, powers and duties of the Administrative Agent and the term “Administrative Agent” shall mean such successor agent effective upon such appointment and approval, and the former Agent’s rights, powers and duties as Administrative Agent shall be terminated, without any other or further act or deed on the part of such former Agent or any of the parties to this Agreement or any holders of the Loans. If no successor agent has accepted appointment as Administrative Agent by the date that is 10 days following a retiring Agent’s notice of resignation (the “Resignation Effective Date”), the retiring Agent’s resignation shall nevertheless thereupon become effective, and the Lenders shall assume and perform all of the duties of the Administrative Agent hereunder until such time, if any, as the Required Lenders appoint a successor agent as provided for above. After any retiring Agent’s resignation as Administrative Agent the provisions of Section 9.7 shall inure to its benefit as to any actions taken or omitted to be taken by it while it was an Agent under this Agreement and the other Loan Documents.

(b)If the Person serving as Administrative Agent is a Defaulting Lender pursuant to clause (e) of the definition thereof, the Required Lenders may, to the extent permitted by applicable law, by notice in writing to the Borrower and such Person remove such Person as Administrative Agent and, shall appoint a successor, subject to the approval of the Borrower (unless an Event of Default under Section 8(f) with respect to the Borrower shall have occurred and be continuing), which approval shall not be unreasonably withheld, conditioned or delayed. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days (or such earlier day as shall be agreed by the Required Lenders) (the “Removal Effective Date”), then such removal shall nonetheless become effective in accordance with such notice on the Removal Effective Date.

(c)With effect from the Resignation Effective Date or the Removal Effective Date (as applicable) (i) the retiring or removed Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents (except that in the case of any Senior Bond held by the Administrative Agent on behalf of the Lenders, the retiring or removed Administrative Agent shall continue to hold such Senior Bond in its name until such time as a successor Administrative Agent is appointed) and (ii) except for any indemnity payments or other amounts then owed to the retiring or removed Administrative Agent, all payments, communications and determinations provided to be made by, to or through the Administrative Agent shall instead be made by or to each Lender directly, until such time, if any, as the Required Lenders appoint a successor Administrative Agent as provided for above. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring or removed Agent (other

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than any rights to indemnity payments or other amounts owed to the retiring or removed Agent as of the Resignation Effective Date or the Removal Effective Date (as applicable)), and the retiring or removed Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents. The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring or removed Agent’s resignation or removal hereunder and under the other Loan Documents, the provisions of this Section and Sections 2.17 and 10.5 shall continue in effect for the benefit of such retiring or removed Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring or removed Agent was acting as Agent.

1.8Documentation Agents and Syndication Agents. None of the Documentation Agents or the Syndication Agents shall have any duties or responsibilities hereunder in its capacity as such.

1.9Administrative Agent May File Proofs of Claim. In case of the pendency of any proceeding under any Debtor Relief Law, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered (but not obligated) by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Obligations that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Sections 2.6, 2.17 and 10.5) allowed in such judicial proceeding; and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Sections 2.6, 2.17 and 10.5.

1.10Certain ERISA Matters.

(a)Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:

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Section 37.such Lender is not using “plan assets” (within the meaning of Section 3(42) of ERISA or otherwise) of one or more Benefit Plans with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments or this Agreement,

Section 38.the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement,

Section 39.(A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loans, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement, or

Section 40.such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

(a)In addition, unless either (1) sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or (2) a Lender has provided another representation, warranty and covenant in accordance with sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that the Administrative Agent is not a fiduciary with respect to the assets of such Lender involved in such Lender’s entrance into, participation in, administration of and performance of the Loans, the Commitments and this Agreement (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Loan Document or any documents related hereto or thereto).

1.2Erroneous Payment.

(a)If the Administrative Agent notifies a Lender or any Person who has received funds on behalf of a Lender, such Lender (any such Lender or other recipient, a “Payment Recipient”) that the Administrative Agent has determined in its sole discretion (whether or not after receipt of any notice under immediately succeeding clause (b)) that any funds received by such Payment Recipient from the Administrative Agent or any of its Affiliates were erroneously transmitted to, or otherwise erroneously or mistakenly received by, such Payment Recipient (whether or not known to such Lender or other Payment Recipient on its behalf) (any such funds, whether received as a

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payment, prepayment or repayment of principal, interest, fees, distribution or otherwise, individually and collectively, an “Erroneous Payment”) and demands the return of such Erroneous Payment (or a portion thereof), such Erroneous Payment shall at all times remain the property of the Administrative Agent and shall be segregated by the Payment Recipient and held in trust for the benefit of the Administrative Agent, and such Lender shall (or, with respect to any Payment Recipient who received such funds on its behalf, shall cause such Payment Recipient to) promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such Erroneous Payment (or portion thereof) as to which such a demand was made, in same day funds (in the currency so received), together with interest thereon in respect of each day from and including the date such Erroneous Payment (or portion thereof) was received by such Payment Recipient to the date such amount is repaid to the Administrative Agent in same day funds at the greater of the Federal Funds EffectiveNYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect. A notice of the Administrative Agent to any Payment Recipient under this clause (a) shall be conclusive, absent manifest error.

(b)Without limiting immediately preceding clause (a), each Lender, or any Person who has received funds on behalf of a Lender, such Lender, hereby further agrees that if it receives a payment, prepayment or repayment (whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise) from the Administrative Agent (or any of its Affiliates) (x) that is in a different amount than, or on a different date from, that specified in a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates) with respect to such payment, prepayment or repayment, (y) that was not preceded or accompanied by a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates), or (z) that such Lender, or other such recipient, otherwise becomes aware was transmitted, or received, in error or by mistake (in whole or in part) in each case:

(i)(A) in the case of immediately preceding clauses (x) or (y), an error shall be presumed to have been made (absent written confirmation from the Administrative Agent to the contrary) or (B) an error has been made (in the case of immediately preceding clause (z)), in each case, with respect to such payment, prepayment or repayment; and

(ii)such Lender shall (and shall cause any other recipient that receives funds on its respective behalf to) promptly (and, in all events, within one Business Day of its knowledge of such error) notify the Administrative Agent of its receipt of such payment, prepayment or repayment, the details thereof (in reasonable detail) and that it is so notifying the Administrative Agent pursuant to this Section 9.13(b), and upon demand from the Administrative Agent, it shall promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such payment, prepayment or repayment as to which such a demand was made in same day funds, together with interest thereon in respect of each day from and including the date such payment, prepayment or repayment was received by such Lender to the date such amount is repaid to the Administrative Agent at the greater of the NYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect.

(c)Each Lender hereby authorizes the Administrative Agent to set off, net and apply any and all amounts at any time owing to such Lender under any Loan Document, or otherwise payable or distributable by the Administrative Agent to such Lender from any source, against any amount due to the Administrative Agent under

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immediately preceding clause (a) or under the indemnification provisions of this Agreement.

(d)The Borrower hereby agrees that in the event an Erroneous Payment (or portion thereof) are not recovered from any Lender that has received such Erroneous Payment (or portion thereof) for any reason, the Administrative Agent shall be subrogated to all the rights of such Lender with respect to such amount.

(e)The parties hereto agree that an Erroneous Payment shall not pay, prepay, repay, discharge or otherwise satisfy any Obligations owed by the Borrower, except, in each case, to the extent such Erroneous Payment is, and solely with respect to the amount of such Erroneous Payment that is, comprised of funds received by the Administrative Agent from the Borrower for the purpose of making such Erroneous Payment.

(f)To the extent permitted by applicable law, no Payment Recipient shall assert any right or claim to an Erroneous Payment, and hereby waives, and is deemed to waive, any claim, counterclaim, defense or right of set-off or recoupment with respect to any demand, claim or counterclaim by the Administrative Agent for the return of any Erroneous Payment received, including without limitation waiver of any defense based on “discharge for value” or any similar doctrine.

(g)Each party’s obligations, agreements and waivers under this Section 9.13 shall survive the resignation or replacement of the Administrative Agent, any transfer of rights or obligations by, or the replacement of a Lender, the termination of the Commitments and/or the repayment, satisfaction or discharge of all Obligations (or any portion thereof) under any Loan Document.

Section 41.MISCELLANEOUS

1.1Amendments and Waivers. Subject to Section 2.13(b) and (c), neither this Agreement, any other Loan Document, nor any terms hereof or thereof may be amended, supplemented or modified except in accordance with the provisions of this Section 10.1. The Required Lenders and the Borrower may, or, with the written consent of the Required Lenders, the Administrative Agent and the Borrower may, from time to time, (a) enter into written amendments, supplements or modifications hereto and to the other Loan Documents for the purpose of adding any provisions to this Agreement or the other Loan Documents or changing in any manner the rights of the Lenders or of the Borrower hereunder or thereunder or (b) waive, on such terms and conditions as the Required Lenders or the Administrative Agent, as the case may be, may specify in such instrument, any of the requirements of this Agreement or the other Loan Documents or any Default or Event of Default and its consequences; provided, however, that no such waiver and no such amendment, supplement or modification shall:

Section 42.forgive the principal amount or extend the final scheduled date of maturity of any Loan, reduce the stated rate of any interest or fee payable hereunder (except in connection with the waiver of applicability of any post-default increase in interest rates (which waiver shall be effective with the consent of the Required Lenders)) or extend the scheduled date of any payment thereof, in each case without the written consent of each Lender directly affected thereby;

Section 43.eliminate or reduce the voting rights of any Lender under this Section 10.1 or Section 10.6(a)(i) without the written consent of such Lender;

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Section 44.reduce any percentage specified in the definition of Required Lenders without the written consent of all Lenders;

Section 45.amend, modify or waive any provision of Section 2.14, Section 10.07 (Application of Money Collected) of the FMB Indenture or any similar provision in the Loan Documents related to pro rata treatment without the consent of each Lender directly affected thereby;

Section 46.amend, modify or waive any provision of Section 9 without the written consent of the Administrative Agent;

Section 47.[reserved];

Section 48.amend, modify or waive any provision of Section 5.1 without the written consent of all the Lenders;

Section 49.amend, modify or waive any provision of Section 2.8(b) without the written consent of each Lender affected thereby;

Section 50.amend or modify any provision in any Loan Document in a manner that by its terms affects the rights or duties under this Agreement of the Lenders of one Tranche (but not the other Tranche), without the prior written consent of the requisite number or percentage in interest of each affected Tranche of Lenders that would be required to consent thereto under this Section if such Tranche of Lenders were the only Tranche of Lenders hereunder at the time; or

Section 51.instruct the Administrative Agent to vote the Senior Bonds in favor of the release of all or substantially all of the Mortgaged Property without the written consent of all the Lenders.

Any such waiver and any such amendment, supplement or modification shall apply equally to each of the Lenders and shall be binding upon the Borrower, the Lenders, the Administrative Agent and all future holders of the Loans. In the case of any waiver, the Borrower, the Lenders and the Administrative Agent shall be restored to their former position and rights hereunder and under the other Loan Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; but no such waiver shall extend to any subsequent or other Default or Event of Default, or impair any right consequent thereon.

Notwithstanding anything to the contrary contained in this Section 10.1, if the Administrative Agent and the Borrower acting together identify any ambiguity, omission, mistake, typographical error or other defect in any provision of this Agreement or any other Loan Document, then the Administrative Agent and the Borrower shall be permitted to amend, modify or supplement such provision to cure such ambiguity, omission, mistake, typographical error or other defect, and any such amendment, modification or supplement shall become effective without any further action or consent of any other party to this Agreement.

If the Required Lenders shall have approved any amendment which requires the consent of all of the Lenders, the Borrower shall be permitted to replace any non-consenting Lender with another financial institution, provided that, (i) the replacement financial institution shall purchase at par, all Loans and other amounts owing to such replaced Lender on or prior to the date of replacement, (ii) the Borrower shall be liable to such replaced Lender under Section 2.17 if any EurodollarTerm Benchmark Loan owing to

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such replaced Lender shall be purchased other than on the last day of the Interest Period relating thereto (as if such purchase constituted a prepayment of such Loans), (iii) such replacement financial institution, if not already a Lender, shall be reasonably satisfactory to the Administrative Agent, (iv) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 10.6 (provided that the Borrower shall be obligated to pay the registration and processing fee referred to therein) (for the avoidance of doubt, such replacement shall be effective subject to the conditions in the other clauses set forth in this proviso, regardless of whether such replaced Lender enters into an Assignment and Assumption) and (v) any such replacement shall not be deemed to be a waiver of any rights the Borrower, the Administrative Agent, or any other Lender shall have against the replaced Lender.

Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to approve or disapprove any amendment, supplement, modification, waiver or consent hereunder (and any amendment, supplement, modification, waiver or consent which by its terms requires the consent of all Lenders or each affected Lender may be effected with the consent of the applicable Lenders other than Defaulting Lenders), except that (i) any reduction of the amount of principal or interest owed to such Defaulting Lender shall, in each case, require the consent of such Defaulting Lender, and (ii) a Defaulting Lender’s Percentage shall be taken into consideration along with the Percentage of non-Defaulting Lenders when voting to approve or disapprove any waiver, amendment or modification that by its terms affects any Defaulting Lender more adversely than other affected Lenders.

1.1Notices.

(a)All notices, requests and demands to or upon the respective parties hereto to be effective shall be in writing (including by telecopy), and, unless otherwise expressly provided herein, shall be deemed to have been duly given or made when delivered during the recipient’s normal business hours, or three Business Days after being deposited in the mail, postage prepaid, or, in the case of telecopy notice, when received during the recipient’s normal business hours, addressed as follows in the case of the Borrower and the Administrative Agent, and as set forth in an administrative questionnaire delivered to the Administrative Agent in the case of the Lenders, or to such other address as may be hereafter notified by the respective parties hereto:

Borrower:    Pacific Gas and Electric Company
c/o PG&E Corporation
P.O. Box 770000
San Francisco, California 94177
Attention: Treasurer
Telecopy: (415) 973-8968
Telephone: (415) 973-8956

with a copy to:    Pacific Gas and Electric Company
c/o PG&E Corporation
P.O. Box 770000
San Francisco, California 94177
Attention: General Counsel
Telecopy: (415) 973-5520

Administrative Agent:    JPMorgan Chase Bank, N.A.
500 Stanton Christiana Road

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NCC 5, 1st Floor
Newark, DE 19713-2107
Attention: Mary Crews
Telecopy: (302) 634-5758
Telephone: (302) 634-1417
Email: mary.crews@jpmorgan.com

provided that any notice, request or demand to or upon the Administrative Agent or any Lender shall not be effective until received.

(b)Notices and other communications to the Administrative Agent or the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Section 2 unless otherwise agreed by the Administrative Agent and each Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c)Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient, at its e-mail address as described in the foregoing clause (i), of notification that such notice or communication is available and identifying the website address therefor; provided that, for both clauses (i) and (ii) above, if such notice, email or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient.

(d)(i) The Borrower agrees that the Administrative Agent may, but shall not be obligated to, make the Communications (as defined below) available to the Lenders by posting the Communications on Debt Domain, Intralinks, Syndtrak or a substantially similar electronic transmission system (the “Platform”).

Section 52.The Platform is provided “as is” and “as available.” The Agent Parties (as defined below) do not warrant the adequacy of the Platform and expressly disclaim liability for errors or omissions in the Communications. No warranty of any kind, express, implied or statutory, including, without limitation, any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects, is made by any Agent Party in connection with the Communications or the Platform. In no event shall the Administrative Agent or any of its Related Parties (collectively, the “Agent Parties”) have any liability to the Borrower, any Lender or any other Person or entity for damages of any kind, including, without limitation, direct or indirect, special, incidental or consequential damages, losses or expenses (whether in tort, contract or otherwise) arising out of the Borrower’s or the Administrative Agent’s transmission of Communications through the Platform, except to the extent such liability resulted from the gross negligence or willful misconduct of the Administrative Agent or any of its Related Parties as determined by a court of competent

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jurisdiction in a final non-appealable judgment. “Communications” means, collectively, any notice, demand, communication, information, document or other material provided by or on behalf of the Borrower pursuant to any Loan Document or the transactions contemplated therein which is distributed to the Administrative Agent or any Lender by means of electronic communications pursuant to this Section, including through the Platform.

1.1No Waiver; Cumulative Remedies. No failure to exercise and no delay in exercising, on the part of the Administrative Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Loan Documents shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.

1.2Survival of Representations and Warranties. All representations and warranties made hereunder, in the other Loan Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans hereunder.

1.3Payment of Expenses and Taxes. The Borrower agrees (a) to pay or reimburse the Administrative Agent and the Lenders for all their respective reasonable out of pocket costs and expenses incurred in connection with the development, preparation and execution of, and any amendment, supplement or modification to, this Agreement and the other Loan Documents and any other documents prepared in connection herewith or therewith, and the consummation of the transactions contemplated hereby and thereby, including the reasonable fees and disbursements of only one joint counsel and one joint special California counsel and, if necessary, one joint local counsel in each other relevant jurisdiction to the Administrative Agent and the Lenders (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons) and filing and recording fees and expenses, with statements with respect to the foregoing to be submitted to the Borrower prior to the Effective Date (in the case of amounts to be paid on the Effective Date) and from time to time thereafter on a quarterly basis or such other periodic basis as the Administrative Agent shall deem appropriate, (b) to pay or reimburse each Lender and the Administrative Agent for all its costs and expenses incurred in connection with the enforcement or preservation of its rights under this Agreement, the other Loan Documents and any such other documents, including the reasonable fees and disbursements of only one joint counsel, one joint special California counsel and, if necessary, one local counsel in each other relevant jurisdiction to the Administrative Agent and the Lenders (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons), and (c) to pay, indemnify, and hold each Lender, the Administrative Agent and their respective Affiliates and their respective officers, directors, employees and agents (each, an “Indemnitee”) harmless from and against any and all other liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever whether brought by the Borrower or any other Person, with respect to the execution, delivery, enforcement and performance of, or arising out of or in connection with, this Agreement, the other Loan Documents and any such other documents, including

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any of the foregoing relating to the use of proceeds of the Loans or the violation of, noncompliance with or liability under, any Environmental Law directly or indirectly relating to the Borrower, its Significant Subsidiaries or any of the facilities and properties owned, leased or operated by the Borrower or its Significant Subsidiaries and the reasonable, documented and invoiced fees and expenses of one joint counsel and one joint special California counsel and, if necessary, one joint local counsel in each other relevant jurisdiction to the applicable Indemnitee (and in the case of an actual or perceived conflict of interest, one additional counsel for each applicable jurisdiction to each group of similarly situated affected persons), in connection with claims, actions or proceedings by any Indemnitee against the Borrower under any Loan Document (all the foregoing in this clause (c), collectively, the “Indemnified Liabilities”), provided, that the Borrower shall have no obligation hereunder to any Indemnitee with respect to Indemnified Liabilities to the extent such Indemnified Liabilities resulted from, as determined in a final non-appealable judgment by a court of competent jurisdiction, (x) the gross negligence, bad faith or willful misconduct of such Indemnitee or its Affiliates, (y) the material breach of such Indemnitee’s funding obligations hereunder or (z) a dispute amongst one or more Lenders not arising from the Borrower’s breach of its obligations under the Loan Documents (other than a dispute involving a claim against an Indemnitee for its acts or omissions in its capacity as an arranger, bookrunner, agent or similar role in respect of the Loan Agreement, except, to the extent such acts or omissions are determined by a court of competent jurisdiction by a final and non-appealable judgment to have constituted the gross negligence, bad faith or willful misconduct of such Indemnitee in such capacity). Without limiting the foregoing, and to the extent permitted by applicable law, the Borrower agrees not to assert and to cause its Significant Subsidiaries not to assert, and hereby waives and agrees to cause its Significant Subsidiaries to waive, all rights for contribution or any other rights of recovery with respect to all claims, demands, penalties, fines, liabilities, settlements, damages, costs and expenses of whatever kind or nature, under or related to Environmental Laws, that any of them might have by statute or otherwise against any Indemnitee. All amounts due under this Section 10.5 shall be payable not later than 30 days after written demand therefor, subject to the Borrower’s receipt of reasonably detailed invoices. Statements payable by the Borrower pursuant to this Section 10.5 shall be submitted to Treasurer (Telephone No. (415) 817-8199/(415) 267-7000) (Telecopy No. (415) 267-7265/7268), at the address of the Borrower set forth in Section 10.2(a) with a copy to Chief Counsel, Corporate (Telephone No. (415) 817-8200) (Telecopy No. (415) 817-8225), at the address of the Borrower set forth in Section 10.2(a), or to such other Person or address as may be hereafter designated by the Borrower in a written notice to the Administrative Agent. The agreements in this Section 10.5 shall survive for two years after repayment of the Loans and all other amounts payable hereunder. This Section 10.5 shall not apply with respect to Taxes, other than Taxes that represent claims, damages, losses, liabilities, costs or expenses arising from non-Tax claims.

1.4Successors and Assigns; Participations and Assignments.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may

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assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 10.6.

(b)(i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees (each, an “Assignee”) other than a Defaulting Lender, any Subsidiary of a Defaulting Lender, any natural person (or holding company, investment vehicle or trust for, or owned or operated by or for the primary benefit of, one or more natural persons), the Borrower or any of the Borrower’s Affiliates or Subsidiaries, all or a portion of its rights and obligations under this Agreement (including all or a portion of the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld or delayed) of:

(A)the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender (or an Affiliate of any Lender) or an Approved Fund or, if an Event of Default under Section 8(a), (e) or (f) has occurred and is continuing, any other Person, and providedfurther, that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within ten (10) Business Days after having received notice thereof from the assigning Lender (with a copy to the Administrative Agent); and

(B)the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment of any Loans to an Assignee that is a Lender (or an Affiliate of a Lender) immediately prior to giving effect to such assignment.

Section 53.Assignments shall be subject to the following additional conditions:

(A)except in the case of an assignment to a Lender, an Eligible Assignee that is an Affiliate of any Lender or an assignment of the entire remaining amount of the assigning Lender’s Loans, the amount of the Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $10,000,000 (or, if such Assignee is an Eligible Assignee that is an Affiliate of a Lender, $5,000,000) unless each of the Borrower and the Administrative Agent otherwise consent, provided that (1) no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing and (2) with respect to any Lender party to this Agreement on the Effective Date, such amounts shall be aggregated in respect of such Lender and any Affiliate of such Lender that is an Eligible Assignee;

(B)the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and

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Assumption, together with a processing and recordation fee of $3,500; and

(C)the Assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an administrative questionnaire.

In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the Assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Loans previously requested but not funded by the Defaulting Lender, to each of which the applicable Assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent or any Lender hereunder (and interest accrued thereon) and (y) acquire (and fund as appropriate) its full pro rata share of all Loans in accordance with its Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable law without compliance with the provisions of this paragraph, then the Assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

Section 54.Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) below, from and after the effective date specified in each Assignment and Assumption the Assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, shall have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.15, 2.16, 2.17 and 10.5 but shall be subject to the limitations set forth therein); provided, that except to the extent otherwise expressly agreed by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from the Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 10.6 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section.

Section 55.The Administrative Agent, acting for this purpose as a non-fiduciary agent of the Borrower (and such agency being solely to establish that the relevant obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations), shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, in the absence of manifest error, and the Borrower, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice

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to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

Section 56.Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an Assignee, the Assignee’s completed administrative questionnaire (unless the Assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this Section and any written consent to such assignment required by paragraph (b) of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

(a)(i) Any Lender may, without the consent of the Borrower or the Administrative Agent, sell participations to one or more banks or other entities (other than a Defaulting Lender or the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver that (1) requires the consent of each Lender directly affected thereby pursuant to the proviso to the second sentence of Section 10.1 and (2) directly affects such Participant. Subject to paragraph (c)(ii) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.15, 2.16 and 2.17 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section.

Section 57.Notwithstanding anything to the contrary herein, a Participant shall not be entitled to receive any greater payment under Section 2.15 or 2.16 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent to such greater payments. Any Participant that is a Foreign Lender shall not be entitled to the benefits of Section 2.16 unless such Participant complies with Section 2.16(e).

Section 58.Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any loans or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such loan or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the

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Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(a)Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central bank having jurisdiction over such Lender, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or Assignee for such Lender as a party hereto.

(b)The Borrower, upon receipt of written notice from the relevant Lender, agrees to issue Notes to any Lender requiring Notes to facilitate transactions of the type described in paragraph (d) above.

(c)Notwithstanding the foregoing, any Conduit Lender may assign any or all of the Loans it may have funded hereunder to its designating Lender without the consent of the Borrower or the Administrative Agent and without regard to the limitations set forth in Section 10.6(b). Each of the Borrower, each Lender and the Administrative Agent hereby confirms that it will not institute against a Conduit Lender or join any other Person in instituting against a Conduit Lender any bankruptcy, reorganization, arrangement, insolvency or liquidation proceeding under any state bankruptcy or similar law, for one year and one day after the payment in full of the latest maturing commercial paper note issued by such Conduit Lender; provided, however, that each Lender designating any Conduit Lender hereby agrees to indemnify, save and hold harmless each other party hereto for any loss, cost, damage, expense, obligations, penalties, actions, judgments, suits or any kind whatsoever arising out of its inability to institute such a proceeding against such Conduit Lender during such period of forbearance.

(d)Notwithstanding anything to the contrary in this Section, none of the Agents, in their capacity as Lenders, will assign without the consent of the Borrower, prior to the Effective Date, any of the Commitments held by them on the Effective Date.

(e)Notwithstanding anything to the contrary in this Section 10.6, for the avoidance of doubt, Goldman Sachs Bank USA may assign any amount of its Loans hereunder to Goldman Sachs Lending Partners LLC (or vice versa) without the prior written consent of any other Person.

1.2Adjustments; Set off.

(a)Except to the extent that this Agreement expressly provides for payments to be allocated to a particular Lender, if any Lender (a “Benefitted Lender”) shall receive any payment of all or part of the Obligations owing to it hereunder, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set off, pursuant to events or proceedings of the nature referred to in Section 8(f), or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender, if any, in respect of the

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Obligations owing to such other Lender hereunder, such Benefitted Lender shall purchase for cash from the other Lenders a participating interest in such portion of the Obligations owing to each such other Lender hereunder, or shall provide such other Lenders with the benefits of any such collateral, as shall be necessary to cause such Benefitted Lender to share the excess payment or benefits of such collateral ratably with each of the Lenders; provided, however, that if all or any portion of such excess payment or benefits is thereafter recovered from such Benefitted Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest.

(b)In addition to any rights and remedies of the Lenders provided by law, including other rights of set-off, each Lender shall have the right, without prior notice to the Borrower, any such notice being expressly waived by the Borrower to the extent permitted by applicable law, upon any amount becoming due and payable by the Borrower hereunder (whether at the stated maturity, by acceleration or otherwise), after any applicable grace period, to set off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch, Affiliate or agency thereof to or for the credit or the account of the Borrower; provided, that in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 2.20 and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the Obligations owing to such Defaulting Lender as to which it exercised such right of setoff. Each Lender agrees promptly to notify the Borrower and the Administrative Agent after any such setoff and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such setoff and application.

1.3Counterparts; Electronic Execution; Binding Effect. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Agreement by facsimile transmission, emailed pdf. or any other electronic means that reproduces an image of the actual executed signature page shall be effective as delivery of an original executed counterpart hereof. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Agreement and the transactions contemplated hereby shall be deemed to include an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records

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Act, or any other similar state laws based on the Uniform Electronic Transactions Act; provided that nothing herein shall require the Administrative Agent to accept electronic signatures in any form or format without its prior written consent. Without limiting the generality of the foregoing, the Borrower hereby (i) agrees that, for all purposes, including without limitation, in connection with any workout, restructuring, enforcement of remedies, bankruptcy proceedings or litigation among the Administrative Agent and the Lenders, electronic images of this Agreement or any other Loan Documents (in each case, including with respect to any signature pages thereto) shall have the same legal effect, validity and enforceability as any paper original, and (ii) waives any argument, defense or right to contest the validity or enforceability of the Loan Documents based solely on the lack of paper original copies of any Loan Documents, including with respect to any signature pages thereto. This Agreement shall become binding on the parties hereto when it shall have been executed by the Administrative Agent and the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

1.4Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. Without limiting the foregoing provisions of this Section 10.9, if and to the extent that the enforceability of any provisions in this Agreement relating to Defaulting Lenders shall be limited by Debtor Relief Laws, as determined in good faith by the Administrative Agent, as applicable, then such provisions shall be deemed to be in effect only to the extent not so limited.

1.5Integration. This Agreement and the other Loan Documents represent the entire agreement of the Borrower, the Administrative Agent, and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Administrative Agent, or any Lender relative to the subject matter hereof not expressly set forth or referred to herein or in the other Loan Documents.

1.6GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

1.7Submission To Jurisdiction; Waivers. The Borrower hereby irrevocably and unconditionally:

(a)submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Loan Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non-exclusive jurisdiction of the United States District Court for the Southern District of New York sitting in the Borough of Manhattan (or if such court lacks subject matter jurisdiction, the Supreme Court of the State of New York sitting in the Borough of Manhattan), and any appellate court from any thereof;

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(b)consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c)agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to the Borrower at its address set forth in Section 10.2(a) or at such other address of which the Administrative Agent shall have been notified pursuant thereto;

(d)agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction; and

(e)waives, to the maximum extent not prohibited by law, and agrees not to assert any right it may have to claim or recover in any legal action or proceeding relating to this Agreement or any other Loan Document any special, exemplary, punitive or consequential damages.

NOTHING IN THIS AGREEMENT OR IN ANY OTHER LOAN DOCUMENT SHALL AFFECT ANY RIGHT THAT THE ADMINISTRATIVE AGENT OR ANY LENDER MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AGAINST THE BORROWER OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

1.8Acknowledgments. The Borrower hereby acknowledges that:

(a)it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents;

(b)none of the Administrative Agent or any Lender has any fiduciary relationship with or duty to the Borrower arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between Administrative Agent and Lenders, on one hand, and the Borrower, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

(c)no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrower and the Lenders.

1.9Confidentiality. Each of the Administrative Agent and each Lender agrees to keep confidential in accordance with such party’s customary practices (and in any event in compliance with applicable law regarding material non-public information) all non-public information provided to it by the Borrower, the Administrative Agent or any Lender pursuant to or in connection with this Agreement that is designated by the provider thereof as confidential; provided that nothing herein shall prevent the Administrative Agent or any Lender from disclosing any such information (a) to the Administrative Agent, any other Lender or any Affiliate thereof, (b) subject to an agreement to comply with the provisions of this Section or substantially equivalent provisions, to any actual

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or prospective Transferee, any direct or indirect counterparty to any Swap Agreement (or any professional advisor to such counterparty) or any credit insurance providers, (c) to its employees, directors, agents, attorneys, service providers, accountants and other professional advisors or those of any of its Affiliates (as long as such attorneys, service providers, accountants and other professional advisors are directed to comply with confidentiality requirements substantially equivalent to this Section), (d) upon the request or demand of any Governmental Authority, (e) in response to any order of any court or other Governmental Authority or as may otherwise be required pursuant to any Requirement of Law, (f) if requested or required to do so in connection with any litigation or similar proceeding, (g) that has been publicly disclosed, (h) to the National Association of Insurance Commissioners or any similar organization or any nationally recognized rating agency that requires access to information about a Lender’s investment portfolio in connection with ratings issued with respect to such Lender, (i) in connection with the exercise of any remedy hereunder or under any other Loan Document, (j) any rating agency in connection with rating of the Borrower or its Subsidiaries or the credit facilities provided hereunder or (k) to the extent such information (i) becomes available to the Administrative Agent, any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower or its Subsidiaries or (ii) is independently discovered or developed by a party hereto without utilizing any information received from the Borrower or its Subsidiaries or violating the terms of this Section 10.14, provided that, in the case of clauses (d), (e) and (f) of this Section 10.14, with the exception of disclosure to bank regulatory authorities, the Borrower (to the extent legally permissible) shall be given prompt prior notice so that it may seek a protective order or other appropriate remedy.

1.10WAIVERS OF JURY TRIAL. TO THE FULLEST EXTENT PERMITTED BY LAW, THE BORROWER, THE ADMINISTRATIVE AGENT AND THE LENDERS HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

1.11USA Patriot Act; Beneficial Ownership Regulation. Each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Patriot Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Patriot Act.

1.12Judicial Reference. If any action or proceeding is filed in a court of the State of California by or against any party hereto in connection with any of the transactions contemplated by this Agreement or any other Loan Document, (i) the court shall, and is hereby directed to, make a general reference pursuant to California Code of Civil Procedure Section 638 to a referee (who shall be a single active or retired judge) to hear and determine all of the issues in such action or proceeding (whether of fact or of law) and to report a statement of decision, provided that at the option of any party to such proceeding, any such issues pertaining to a “provisional remedy” as defined in California Code of Civil Procedure Section 1281.8 shall be heard and determined by the court, and (ii) without limiting the generality of Section 10.5, the Borrower shall be solely

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responsible to pay all fees and expenses of any referee appointed in such action or proceeding.

1.13No Advisory or Fiduciary Responsibility. In connection with all aspects of each transactions contemplated hereby (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document), the Borrower acknowledges and agrees that: (i) (A) the arranging and other services regarding this Agreement provided by the Agents, the Arrangers and the Lenders are arm’s-length commercial transactions between the Borrower, on the one hand, and the Agents, the Arrangers and the Lenders, on the other hand, (B) the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate, and (C) the Borrower is capable of evaluating, and understands and accepts, the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents; (ii) (A) each Agent, Arranger and Lender is and has been acting solely as a principal and, except as expressly agreed in writing by the relevant parties, has not been, is not, and will not be acting as an advisor, agent or fiduciary for the Borrower or any other Person and (B) none of the Agents, Arrangers or Lenders has any obligation to the Borrower or any of its Affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents; and (iii) the Agents, the Arrangers and the Lenders and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its Affiliates, and none of the Agents, Arrangers or Lenders has any obligation to disclose any of such interests to the Borrower or its Affiliates. To the fullest extent permitted by law, the Borrower hereby waives and releases any claims that it may have against the Agents, the Arrangers and the Lenders with respect to any breach or alleged breach of agency or fiduciary duty in connection with any aspect of any transaction contemplated hereby other than a breach of the confidentiality provisions set forth in Section 10.14.

1.14Acknowledgement Regarding Any Supported QFCs.

(a)To the extent that the Loan Documents provide support, through a guarantee or otherwise, for Swap Agreements or any other agreement or instrument that is a QFC (such support “QFC Credit Support” and each such QFC a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Loan Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

(b)In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and such QFC

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Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Loan Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Loan Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support..

1.15Acknowledgement and Consent to Bail-In of Affected Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the Write-Down and Conversion Powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(b)the effects of any Bail-In Action on any such liability, including, if applicable:

Section 59.a reduction in full or in part or cancellation of any such liability;

Section 60.a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

Section 61.the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of the applicable Resolution Authority.

[Remainder of page intentionally left blank. Signature pages follow.]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.

PACIFIC GAS AND ELECTRIC COMPANY
By:
	Name:
	Title:

1

JPMORGAN CHASE BANK, N.A. as Administrative Agent and as a Lender
By:
	Name:
	Title:

2

BANK OF AMERICA, N.A. as a Lender
By:
	Name:
	Title:

3

BARCLAYS BANK PLC as a Lender
By:
	Name:
	Title:

4

CITIBANK, N.A. as a Lender
By:
	Name:
	Title:

5

GOLDMAN SACHS BANK USA as a Lender
By:
	Name:
	Title:

6

BNP PARIBAS as a Lender
By:
	Name:
	Title:

By:
	Name:
	Title:

7

CREDIT SUISSE AG, NEW YORK BRANCH as a Lender
By:
	Name:
	Title:

By:
	Name:
	Title:

8

MIZUHO BANK, LTD. as a Lender
By:
	Name:
	Title:

9

MUFG UNION BANK, N.A. as a Lender
By:
	Name:
	Title:

10

WELLS FARGO BANK, NATIONAL ASSOCIATION as a Lender
By:
	Name:
	Title:

11

BANK OF MONTREAL, CHICAGO BRANCH as a Lender
By:
	Name:
	Title:

12

THE BANK OF NEW YORK MELLON as a Lender
By:
	Name:
	Title:

13

BANK OF CHINA, LOS ANGELES BRANCH as a Lender
By:
	Name:
	Title:

14

Execution Version

EX-10.82

EXHIBIT 10.82

Human Resources Executive Recruiting 245 Market Street MAILCODE N2F San Francisco, CA 94105

July 29, 2020

Ajay Waghray

535 Belada Blvd.

Atlanta, Georgia 30342

Dear Ajay:

We are thrilled to extend a contingent offer of employment for the position of Senior Vice President and Chief Information Officer reporting to the PG&E Corporation Chief Executive Officer (currently Bill Smith, Interim Chief Executive Officer and President, PG&E Corporation). This offer is subject to board-level approval of your election to Senior Vice President.

Your total annual compensation package will consist of the following:

1.An annual base salary of $600,000 ($50,000 month) subject to ordinary withholdings.

2.A one-time cash sign-on bonus of $100,000, to be paid on your second payroll check, subject to supplemental withholdings. In addition, a one-time sign-on bonus of $400,000 in Restricted Stock Units (RSUs), with vesting of 40% on the first anniversary of the grant date and 60% on the second anniversary of the grant date.

Should you voluntarily resign from PG&E Corporation (the Company), or, if applicable, its subsidiaries, within two years of your start date, other than your resignation for “Good Reason” as defined in Section 3(a)(9) of the PG&E Corporation 2012 Officer Severance Policy (without regard to the requirement that such “Good Reason” event occur during a “Covered Period” and assuming that you are an “Executive Officer” for purposes of the definition of “Good Reason”), you will repay to the Company the value of both the cash sign-on bonus and the vested RSU sign-on bonus in full, and you will forfeit the value of the unvested RSU sign-on bonus, in each case determined as of the effective date of your resignation.

3.Participation in the Company's Short-Term Incentive Plan (STIP) with a target participation rate of 60% of your eligible earnings (i.e., base salary) received during each plan year. You must be on the Company’s (or Pacific Gas and Electric Company’s (the Utility’s)) active payroll as of September 30 of each year to be eligible for a payout for that year. The STIP is an at-risk component of pay that rewards employees annually and is tied to company and individual performance. The STIP for 2020 has been proposed and is awaiting final approval. STIP awards are completely discretionary and not guaranteed. The PG&E Corporation Compensation Committee retains full discretion with respect to awarding STIP payments. For an employment period that does not span the entire calendar year, the STIP will be pro-rated for the period in which you were on the Company’s or the Utility’s active payroll.

4.Participation in the Company’s Long-Term Incentive Plan (LTIP) with a target annual award of $650,000. LTIP awards typically are granted in March of each year. LTIP

Ajay Waghray

July 29, 2020

Page 2

awards may consist of RSUs, performance shares, stock options, or a combination of these. RSUs and stock options are subject to time-based vesting. The value of performance shares typically is determined after the end of a three-year performance period, at which time the performance shares vest in the applicable percentage. The LTIP for 2020 has been proposed and is awaiting final approval. The Compensation Committee retains full discretion with respect to the approval of LTIP award form, amounts and terms.

The proposed 2020 LTIP design consists entirely of performance shares.

5.Participation in the PG&E Corporation Retirement Savings Plan (RSP), a 401(k) savings plan. You will be eligible to contribute as much as 50% of your salary on either a pre-tax or after-tax basis. We will match contributions up to 8% of your salary at 75 cents on each dollar contributed. All of the above contributions are subject to the applicable legal limits and the overall terms of the plan.

6.Participation in the PG&E Corporation Supplemental Retirement Savings Plan (SRSP), a non-qualified, deferred compensation plan. You may elect to defer payment of some of your compensation on a pre-tax basis, subject to IRS and other legal restrictions and the overall terms of the plan. Additionally, we will provide you with the full matching contributions that cannot be provided through the RSP due to legal limitations imposed on highly-compensated employees.

7.Conditioned upon meeting plan requirements, you also will be eligible for retirement benefits under the Company’s and the Utility’s retirement—qualified cash balance pension and supplemental Defined-Contribution Supplemental Executive Retirement Plan (DC-ESRP)—post-retirement life insurance and retiree medical plans.

The cash balance pension is subject to income limitations set by the Internal Revenue Service (IRS) each year—your base pay up to that limit will be used to determine your qualified pension benefit. Your compensation over the IRS limit will be used to determine your benefit under the DC-ESRP, which is the supplemental pension plan for officers and includes both base pay and STIP earnings. You will not participate in the Pacific Gas and Electric Company Retirement Excess Plan, which is the supplemental pension plan for non-officer employees and uses a different methodology to calculate supplemental pension benefits (including only base pay, not STIP earnings).

8.An annual Paid Time Off (PTO) allotment of four weeks, subject to future increases based on length of service as determined by the overall terms of the PTO program. For your first year, the PTO allotment will be prorated based on your date of hire. In addition, the Company recognizes ten paid company holidays and provides three floating holidays immediately upon hire.

9.An annual perquisite allowance of $20,000, subject to ordinary withholdings, normally included on your March paycheck.

For 2020, because your start date is after June 30, you will receive 50% of the annual perquisite allowance ($10,000) on your second regular monthly paycheck.

10.Participation in the Company’s and certain Utility health benefits programs, which permit you to select coverage tailored to your personal needs and circumstances. Information and instructions on how to enroll in health plan benefits will be provided to you within your first ten days of employment. The benefits options you choose will be effective on your date of hire. You have 31 days from your start date to make health and welfare benefit choices that best fit your needs.

11.Our employment offer also includes a comprehensive relocation package. The major components include reimbursement of home sale and home purchase closing costs, the

Ajay Waghray

July 29, 2020

Page 3

move of your household goods, one house hunting trip, temporary corporate housing, a $7,000 move allowance and a final trip to your new location.

Altair, our relocation vendor partner, will contact you no later than 30 days before your start date to thoroughly review the relocation program with you. They will provide you with the details of the program and partner with you throughout the entire relocation process. If you receive no call from Altair, please email Relocation Services at RelocationServices@pge.com. Should you decide to resign from the Company within two years of your start date, you will be obligated to repay a pro-rated amount of the cost of the relocation package based on your resignation date. You will also be required to sign an additional agreement, detailing the terms and conditions of the relocation program.

The general overall terms of the Company’s and the Utility’s compensation and benefit programs (including but not limited to STIP, LTIP, perquisite allowance, qualified and supplemental pension, time off, and healthcare offerings) are subject to change over time. No portion of this letter is intended to indicate a guarantee of the terms and conditions of such programs existing at the time of this offer. The Company may not amend the initial terms of your annual compensation package, position, reporting structure or eligibility for severance benefits as described in this letter without your written consent.

You will be an employee at will, meaning the Company can terminate your employment at any time, with or without cause and with or without notice. In the event you are terminated without cause, you will be eligible for benefits under the PG&E Corporation Officer Severance Policy, attached. In addition, if you resign within two years of your start date for “Good Reason” as defined in section 3(a)(9) of the PG&E Corporation 2012 Officer Severance Policy (Policy)—without regard to the requirement that such “Good Reason” event occur during a “Covered Period” (as defined in the Policy) and assuming that you are an “Executive Officer” (for purposes of the definition of “Good Reason”)—then you will receive a payment equivalent to that calculated under section 2(a)(1) of the Policy (assuming a Severance Multiple of 12), payable in accordance with section 2(a)(1), and subject to sections 2(d), 3(b) (as applicable),12, 13, and 14 of the Policy as applicable to this potential payment.

The offer is contingent on your passing comprehensive background verification and a standard drug analysis test. We will also verify your eligibility to work in the United States based on applicable immigration laws.

Ajay Waghray

July 29, 2020

Page 4

We look forward to you joining our executive team.

Sincerely,

Dinyar Mistry

Senior Vice President, Human Resources

PG&E Corporation & Pacific Gas and Electric Company

Att: PG&E Corporation Officer Severance Policy

Please acknowledge your acceptance of this offer and the terms of this letter by signing the original and returning it to Executive Recruiting.

Signature Date

EX-10.83

EXHIBIT 10.83

Human Resources Executive Recruiting 77 Beale Street San Francisco, CA 94105

January 8, 2021

Julius Cox

4023 Redford Court

New Albany, OH 43054

Dear Julius:

We are thrilled to extend a contingent offer of employment for the position of Executive Vice President, People and Shared Services reporting to Patti Poppe, PG&E Corporation Chief Executive Officer. This offer is subject to board approval of your election to Executive Vice President.

Your total annual compensation package will consist of the following:

1.An annual base salary of $610,000 ($50,833.33 month) subject to ordinary withholdings.

2.A one-time cash sign-on bonus of $400,000, to be paid on your second payroll check, subject to supplemental withholdings. Should you voluntarily resign within two years of your start date, you will be obligated to repay the cash bonus in full.

3.A one-time new hire award of $450,000 in Restricted Stock Units (RSUs) that vest pro rata, one-half per year on each of the first two anniversaries of the grant date. The grant date of your RSU award will be the later of your hire date or the date the award is approved by the Compensation Committee of the PG&E Corporation board, or, if your grant date otherwise would occur during a “trading blackout” period, the first business day after the trading blackout ends. The initial value of your award is used to determine the number of RSUs you receive on the grant date. The ultimate value that you realize will depend on your employment status and the performance of PG&E Corporation common stock. You will receive additional details on the award when it is granted.

4.Participation in the Pacific Gas and Electric Company (the Company) Short-Term Incentive Plan (STIP) with an initial target participation rate of 60% of your eligible earnings (i.e., base salary) received during each plan year. The STIP is an at-risk component of pay that rewards employees annually and is tied to company and individual performance. The STIP design for 2021 has been proposed and is awaiting final approval. STIP awards are completely discretionary and not guaranteed. The PG&E Corporation Compensation Committee retains full discretion with respect to awarding STIP payments.

5.Participation in the PG&E Corporation Long-Term Incentive Plan (LTIP) with an initial target annual award of $650,000. LTIP awards typically are granted in March of each year. LTIP awards may consist of RSUs, performance shares, stock options, or a combination of these. RSUs and stock options are subject to time-based vesting. The value of performance shares is determined after the end of a three-year performance period, at which time the performance shares vest in the applicable percentage. The LTIP design for 2021 has been proposed and is awaiting final approval. The Compensation Committee retains full discretion with respect to the approval of LTIP award form, amounts and terms.

Julius Cox

December 30, 2020

Page 2

6.Participation in the PG&E Corporation Retirement Savings Plan (RSP), a 401(k) savings plan. You will be eligible to contribute as much as 50% of your salary on either a pre-tax or after-tax basis. We will match contributions up to 8% of your salary at 75 cents on each dollar contributed. All RSP contributions are subject to applicable legal limits.

7.Participation in the PG&E Corporation Supplemental Retirement Savings Plan (SRSP), a non-qualified, deferred compensation plan. You may elect to defer payment of some of your compensation on a pre-tax basis, subject to IRS and other legal restrictions. Additionally, we will provide you with the full matching contributions that cannot be provided through the RSP due to legal limitations imposed on highly-compensated employees.

8.Conditioned upon meeting plan requirements, retirement benefits under the Company’s qualified and non-qualified pension, post-retirement life insurance, and retiree medical plans.

The qualified pension is subject to income limitations set by the IRS each year—your base pay up to that limit will be used to determine your qualified pension benefit. Your compensation over the IRS limit will be used to determine your benefit under the supplemental pension plan for officers, the Defined-Contribution Supplemental Executive Retirement Plan (DC-ESRP) , which includes both base pay and STIP earnings. You will not participate in the supplemental pension plan for non-officer employees, the Retirement Excess Plan, which uses a different methodology to calculate supplemental pension benefits (including only base pay, not STIP earnings).

9.An initial annual vacation allotment of four weeks, subject to future increases based on length of service. For your first year, the vacation allotment will be pro-rated based on your date of hire. In addition, the Company recognizes ten paid company holidays and provides three floating holidays and two weeks of sick leave immediately upon hire.

10.An initial annual perquisite allowance of $20,000, subject to ordinary withholdings, normally included on your March paycheck.

11.Participation in the Company’s health benefits program, which permits you to select coverage tailored to your personal needs and circumstances.  Information and instructions on how to enroll in health plan benefits will be provided to you within your first ten days of employment. The benefits options you choose will be effective retroactively to your date of hire. You will have 31 days from your start date to make health and welfare benefit choices that best fit your needs. 

12.A comprehensive relocation package, the major components of which include reimbursement of home sale and home purchase closing costs, the move of your household goods, one house-hunting trip, temporary corporate housing, a $7,000 move allowance, and a final trip to your new location.

Altair, our relocation vendor partner, will contact you no later than 30 days before your start date to thoroughly review the relocation program with you. They will provide you with the details of the program and partner with you throughout the entire relocation process.  If you receive no call from Altair, please email Relocation Services at RelocationServices@pge.com. Should you voluntarily resign from the Company within two years of your start date, you will be obligated to repay a pro-rated amount of the cost of the relocation package, based on your resignation date.  You will be required to sign an agreement detailing the terms and conditions of the relocation program.

The general overall terms of PG&E’s compensation and benefit programs (including but not limited to STIP, LTIP, perquisite allowance, qualified and supplemental pension, time off, and

Julius Cox

December 30, 2020

Page 3

healthcare offerings) are subject to change over time. No portion of this letter is intended to indicate a guarantee of the terms and conditions of such programs existing at the time of this offer.

You will be an employee at will, meaning the Company can terminate your employment at any time, with or without cause and with or without notice. In the event you are terminated without cause, you will be eligible for benefits under the PG&E Corporation Officer Severance Policy.

The offer is contingent on your passing a comprehensive background verification and a standard drug analysis test. We will also verify your eligibility to work in the United States based on applicable immigration laws.

We look forward to you joining our executive team.

Sincerely,

Mary King

Vice President, Talent & Chief Diversity Officer

Pacific Gas and Electric Company

Please acknowledge your acceptance of this offer and the terms of this letter by signing the original and returning it to Executive Recruiting.

Signature Date

EX-10.84

EXHIBIT 10.84

Human Resources Executive Recruiting 77 Beale Street San Francisco, CA 94105

April 15, 2021

Carla J. Peterman

628 Balboa Drive

Seal Beach, CA 90740

Dear Carla:

We are thrilled to extend a contingent offer of employment for the position of Executive Vice President, Corporate Affairs of PG&E Corporation reporting to the Chief Executive Officer, PG&E Corporation. This offer is subject to board approval of your election to Executive Vice President.

Your total annual compensation package will consist of the following:

1.An annual base salary of $560,000 ($46,666.66 month) subject to ordinary withholdings, payable monthly on the 23rd of the month or prior business day in accordance with PG&E’s1 standard payroll practice.

2.One-time cash sign-on bonus of $290,000 to be paid on your second payroll check, subject to supplemental withholdings. Should you voluntarily resign within two years of your start date, you will be obligated to repay the cash bonus in full.

3.A one-time new hire award of $270,000 in Restricted Stock Units (RSUs) that vest pro rata, one-half per year on each of the first two anniversaries of the grant date. The grant date of your RSU award will be the later of your hire date or the date the award is approved by the Compensation Committee of the PG&E Corporation board, or, if your grant date otherwise would occur during a “trading blackout” period, the first business day after the trading blackout ends. The initial value of your award is used to determine the number of RSUs you receive on the grant date. The ultimate value that you realize will depend on your employment status and the performance of PG&E Corporation common stock. You will receive additional details on the award when it is granted.

4.Participation in the PG&E Corporation Short-Term Incentive Plan (STIP) with an initial target participation rate of 60% of your eligible earnings (i.e., base salary) received during each plan year. The STIP is an at-risk component of pay that rewards employees annually and is tied to company and individual performance. STIP awards are completely discretionary and not guaranteed. The PG&E Corporation Compensation Committee retains full discretion with respect to awarding STIP payments.

5.Participation in the PG&E Corporation Long-Term Incentive Plan (LTIP) with an initial target award of $1,120,000 for 2021. LTIP awards typically are granted in March of each year; if your start date is after the regular annual awards are granted, the grant date of your 2021 award will be the later of your start date or the first business day

1     For purposes of this document, “PG&E” refers to Pacific Gas and Electric Company and PG&E Corporation collectively.

Carla J. Peterman

April 15, 2021

Page 2

after any then-effective trading blackout ends. The Compensation Committee retains full discretion with respect to the approval of LTIP award form, amounts and terms.

6.Participation in the PG&E Corporation Retirement Savings Plan (RSP), a 401(k) savings plan. You will be eligible to contribute as much as 50% of your salary on either a pre-tax or after-tax basis. We will match contributions up to 8% of your salary at 75 cents on each dollar contributed. All RSP contributions are subject to applicable legal limits.

7.Participation in the PG&E Corporation Supplemental Retirement Savings Plan (SRSP), a non-qualified, deferred compensation plan. You may elect to defer payment of some of your compensation on a pre-tax basis, subject to IRS and other legal restrictions. Additionally, we will provide you with the full matching contributions that cannot be provided through the RSP due to legal limitations imposed on highly-compensated employees.

8.Subsidized financial planning services through AYCO, a Goldman Sachs company, including financial planning, asset management, and tax services. The PG&E subsidy is equal to 40% of your total cost.

9.Conditioned upon meeting plan requirements, retirement benefits under PG&E’s qualified and non-qualified pension, post-retirement life insurance, and retiree medical plans.

The qualified pension is subject to income limitations set by the IRS each year—your base pay up to that limit will be used to determine your qualified pension benefit. Your total compensation, irrespective of the IRS limit, will be used to determine your benefit under the supplemental pension plan for officers, the Defined-Contribution Supplemental Executive Retirement Plan (DC-ESRP), which includes both base pay and STIP earnings. You will not participate in the supplemental pension plan for non-officer employees, the Retirement Excess Plan, which uses a different methodology to calculate supplemental pension benefits (including only base pay, not STIP earnings).

10.An initial annual Paid Time Off allotment of four weeks, subject to future increases based on length of service. For your first year, the PTO allotment will be pro-rated based on your date of hire. In addition, PG&E recognizes ten paid company holidays and three floating holidays immediately upon hire.

11.An initial annual perquisite allowance of $25,000, subject to ordinary withholdings, normally included on your March paycheck. Since your start date will be after March 1st, the allowance will be provided on your second payroll check.

12.Participation in the Company’s health benefits program, which permits you to select coverage tailored to your personal needs and circumstances.  Information and instructions on how to enroll in health plan benefits will be provided to you within your first ten days of employment. The benefits options you choose will be effective retroactively to your date of hire. You will have 31 days from your start date to make health and welfare benefit choices that best fit your needs. 

13.A health and fitness assessment program designed to promote a healthy lifestyle.The program focuses on early detection through annual comprehensive health assessments, and lifestyle enhancement for optimum health and longevity.

14.A comprehensive relocation package, the major components of which include reimbursement of home purchase closing costs, the move of your household goods, temporary corporate housing, and a $7,000 relocation expense allowance.

Carla J. Peterman

April 15, 2021

Page 3

Altair, our relocation vendor partner, will contact you no later than 30 days before your start date to thoroughly review the relocation program with you. They will provide you with the details of the program and partner with you throughout the entire relocation process. If you receive no call from Altair, please email Relocation Services at RelocationServices@pge.com. Should you voluntarily resign from PG&E within two years of your start date, you will be obligated to repay a pro-rated amount of the cost of the relocation package, based on your resignation date. You will be required to sign an agreement detailing the terms and conditions of the relocation program.

The general overall terms of PG&E’s compensation and benefit programs (including but not limited to STIP, LTIP, perquisite allowance, qualified and supplemental pension, time off, and healthcare offerings) are subject to change over time. No portion of this letter is intended to indicate a guarantee of the terms and conditions of such programs existing at the time of this offer.

You will be an employee at will, meaning PG&E can terminate your employment at any time, with or without cause and with or without notice. In the event you are terminated without cause, you will be eligible for benefits under the PG&E Corporation Officer Severance Policy, including pro-rata STIP for partial-year service over six months as noted in such policy.

The offer is contingent on your passing a comprehensive background verification and a standard drug analysis test. We will also verify your eligibility to work in the United States based on applicable immigration laws.

We look forward to you joining our executive team.

Sincerely,

Mary King

Vice President, Talent & Chief Diversity Officer

Pacific Gas and Electric Company

Please acknowledge your acceptance of this offer and the terms of this letter by signing the original and returning it to Executive Recruiting.

Signature Date

EX-10.85

EXHIBIT 10.85

Human Resources, Executive Recruiting 245 Market Street San Francisco, CA 94177

June 30, 2020

Sumeet Singh

6116 Alpine Blue Drive

San Ramon, CA 94582

Dear Sumeet:

On behalf of PG&E Corporation, I am pleased to offer you the position of Senior Vice President and Chief Risk Officer, reporting to Bill Smith, Interim Chief Executive Officer, PG&E Corporation, with an expected start date of August 1, 2020 or at your earliest availability. This offer is subject to board approval of your election to Senior Vice President.

Your total annual compensation package will consist of the following:

1.An annual base salary of $475,000 ($39,583.33 month) subject to ordinary withholdings.

2.A sign-on bonus of $75,000, subject to ordinary withholdings, that will be paid within 10 days of the first day of your employment.

3.Participation in the Company's Short-Term Incentive Plan (STIP) with a target participation rate of 60% of your eligible earnings (i.e., base salary) received during each plan year. You must be on PG&E’s active payroll as of September 30 of each year to be eligible for a payout for that year. The STIP is an at-risk component of pay that rewards employees annually and is tied to company and individual performance. The STIP for 2020 has been proposed and is awaiting final approval. STIP awards are completely discretionary and not guaranteed. The PG&E Corporation Compensation Committee retains full discretion with respect to awarding STIP payments. For an employment period that does not span the entire calendar year, the STIP will be pro-rated for the period in which you were on PG&E’s active payroll.

4.Participation in PG&E’s Long-Term Incentive Plan (LTIP) with a target annual award of $650,000. LTIP awards typically are granted in March of each year. LTIP awards may consist of Restricted Stock Units (RSUs), performance shares, stock options, or a combination of these. RSUs and stock options are subject to time-based vesting. The value of performance shares is determined after the end of a three-year performance period, at which time the performance shares vest in the applicable percentage. The LTIP for 2020 has been proposed and is awaiting final approval. The Compensation Committee retains full discretion with respect to the approval of LTIP award form, amounts and terms.

The proposed 2020 LTIP design consists entirely of performance shares.

5.Participation in the PG&E Corporation Retirement Savings Plan (RSP), a 401(k) savings plan. You will be eligible to contribute as much as 50% of your salary on either a pre-tax

1

or after-tax basis. We will match contributions up to 6% of your salary at 75 cents on each dollar contributed. All of the above contributions are subject to the applicable legal limits.

6.Participation in the PG&E Corporation Supplemental Retirement Savings Plan (SRSP), a non-qualified, deferred compensation plan. You may elect to defer payment of some of your compensation on a pre-tax basis, subject to IRS and other legal restrictions. Additionally, we will provide you with the full matching contributions that cannot be provided through the RSP due to legal limitations imposed on highly-compensated employees.

7.Conditioned upon meeting plan requirements, you also will be eligible for retirement benefits under the Company’s retirement (final average pay pension and Defined-Contribution Supplemental Executive Retirement Plan), post-retirement life insurance and retiree medical plans.

Since your break in service was less than twelve months, your service for purposes of the final average pay pension will be bridged; that is, it will be treated as if you had had no break. The Defined-Contribution Supplemental Executive Retirement Plan requires three years of cumulative service with either PG&E Corporation or Pacific Gas and Electric Company, so you will be immediately vested in this benefit due to your prior service.

8.Participation in the PG&E Corporation paid time off (PTO) program and Short-Term and Long-Term Disability programs. You will receive an annual PTO allotment of 160 hours, subject to future increases based on length of service. In addition, PG&E Corporation recognizes ten paid company holidays and provides three floating holidays immediately upon hire.

9.An annual perquisite allowance of $20,000, subject to ordinary withholdings, normally included on your March paycheck.

For 2020, because your start date is after June 30, you will receive 50% of the annual perquisite allowance ($10,000) on your second regular monthly paycheck.

10.Participation in the Company’s health benefits program, which permits you to select coverage tailored to your personal needs and circumstances.  Information and instructions on how to enroll in health plan benefits will be provided to you within your first ten days of employment. The benefits options you choose will be effective on your date of hire. You have 31 days from your start date to make health and welfare benefit choices that best fit your needs. 

The general overall terms of PG&E’s compensation and benefit programs (including but not limited to STIP, LTIP, perquisite allowance, qualified and non-qualified pension, time off, and healthcare offerings) are subject to change over time. No portion of this letter is intended to indicate a guarantee of the terms and conditions of such programs existing at the time of this offer.

2

You will be an employee at will, meaning the Company can terminate your employment at any time, with or without cause and with or without notice. In the event you are terminated without cause, you will be eligible for benefits under the PG&E Corporation Officer Severance Policy adjusted to 18 months.

The offer is contingent on your passing comprehensive background verification and a standard drug analysis test. We will also verify your eligibility to work in the United States based on applicable immigration laws.

We look forward to you re-joining our executive team.

Sincerely,

Dinyar Mistry

Senior Vice President, Human Resources

PG&E Corporation & Pacific Gas and Electric Company

Please acknowledge your acceptance of this offer and the terms of this letter by signing the original and returning it to Executive Recruiting.

Signature Date

3

EX-10.92

EXHIBIT 10.92

PG&E CORPORATION
2014 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below (sometimes referred to as “you”). The Restricted Stock Units have been granted under the PG&E Corporation 2014 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the “Agreement”).

Date of Grant:     March 1, 2021    

Name of Recipient:     Julius Cox    

Recipient’s Participant ID:     XXXXXXX    

Number of Restricted Stock Units:     41,021    

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 2021.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar days of the date of this award at ATTN: LTIP Administrator, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION
2014 LONG-TERM INCENTIVE PLAN

NON-ANNUAL RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LTIP. In the event of any conflict between the provisions of this Agreement or the above cover sheet and the PG&E Corporation 2012 Officer Severance Policy, this Agreement or the above cover sheet will govern, as applicable. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown on the cover sheet, will vest in accordance with the below vesting schedule (the “Normal Vesting Schedule”).        20,510 on March 01, 2022        20,511 on March 01, 2023 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Section 409A of the Internal Revenue Code of 1986, as amended (“Code”). Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment will then be cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.

Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event that cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the RSUs are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation will issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance will, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death, or (3) “separation from service,” within the meaning of Code Section 409A within 2 years following a Change in Control.
Voluntary Termination	In the event of your voluntary termination (other than Retirement), all unvested Restricted Stock Units will be cancelled on the date of termination.
Retirement	[In the event of your Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such Retirement had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however, that in the event of your Retirement within 2 years following a Change in Control, those Restricted Stock Units that would have vested within 12 months following such Retirement will be vested and settled as soon as practicable after (but not later than 60 days after) the date of such Retirement. All other unvested Restricted Stock Units will be cancelled. Your voluntary termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least eight consecutive years ending on the date of termination of your employment.

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Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense, or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation. For the avoidance of doubt, you will not be eligible to retire if your employment is being or is terminated for cause.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause or Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.
Death/Disability	In the event of your death or Disability (as defined in Code Section 409A) while you are employed, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder will be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	If your employment is terminated (other than for cause, your voluntary termination, or your Retirement) (1) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Code Section 424(f), or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will vest and be settled in the same manner as for a “Termination other than for Cause” described above.

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Change in Control	In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither so assumed nor so continued by the Acquiror, and the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units will vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause, your voluntary termination, or your Retirement) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) will vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement. In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this award) will vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Delay	PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Code Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.

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Withholding Taxes

The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.

Leaves of Absence

For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you will be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence will be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.

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Voting and Other Rights	You will not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent). No Restricted Stock Units and no shares of Stock that have not been issued hereunder may be sold, assigned, transferred, pledged, or otherwise encumbered, other than by will or the laws of decent and distribution, and the Restricted Stock Units may be exercised during the life of the Recipient only by the Recipient or the Recipient’s guardian or legal representative.
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time, including provisions of the Officer Severance Policy, and provisions of the PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy, as last revised on February 19, 2019 and available on the PG&E@Work internet site for the Long-Term Incentive Plan (the policy and location may be changed from time to time by PG&E Corporation).
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

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PG&E CORPORATION

2014 LONG-TERM INCENTIVE PLAN

A total of 47,000,000 shares of PG&E Corporation common stock (“Shares”), no par value, are available for issuance under the PG&E Corporation 2014 Long-Term Incentive Plan, as may be amended (LTIP), less the number of Shares covered by awards granted under the PG&E Corporation 2006 Long-Term Incentive Plan after December 31, 2013, but prior to the effective date of the LTIP, and determined in accordance with Section 4.1 of the LTIP. The Shares will come from PG&E Corporation’s authorized, but unissued, shares of common stock and/or Shares reacquired by PG&E Corporation on the open market for this purpose. The purpose of the LTIP is to advance the interests of PG&E Corporation and its shareholders by providing officers, key management employees, and other eligible participants with financial incentives tied directly to PG&E Corporation's long-term business objectives. Awards granted under the LTIP can include stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, performance shares, performance units, deferred compensation awards, and other stock-based awards.

This summary describes the stock options, SARs, restricted stock, performance awards, and restricted stock units which may be granted under the LTIP. This summary does not purport to be complete, and is qualified in its entirety by reference to the LTIP and your award agreement evidencing an award. The terms of the LTIP will govern in case there is any conflict with any part of this summary or your individual award agreement. Certain terms of stock options, SARS, restricted stock, restricted stock units, and performance awards differ from those described in this summary and such terms will be set forth in your award agreement governing such award. You may obtain a copy of the LTIP by calling or writing the LTIP Administrator, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, CA 94105, (415) 266-8644.

______________________________

THIS DOCUMENT CONSTITUTES PART OF A PROSPECTUS COVERING SECURITIES THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933.

March 2021

Contents

Information about the LTIP	iv
Administration of the LTIP.	iv
Eligibility.	iv
Duration of the LTIP.	iv
Adjustment Upon Changes in Number or Value of Shares of Common Stock.	iv
Award Agreements.	iv
Amendment and Termination of the LTIP and Incentive Awards.	iv
Withholding Taxes.	v
Recoupment of Awards.	v
Miscellaneous.	v
Stock Options	v
What is a stock option?	v
Will I be required to pay for a grant of a stock option?	v
When may I exercise my stock options?	v
How do I exercise my stock options?	v
What happens if my service with PG&E Corporation ends before my stock option is fully vested and exercisable?	vi
When do my stock options expire?	vi
Do I have any shareholder rights?	vi
How do I pay for shares and taxes upon exercise of my stock options?	vi
How is an incentive stock option different than a nonqualified stock option?	vi
Stock Appreciation Rights	vi
What is a stock appreciation right?	vi
Will I be required to pay for a grant of stock appreciation rights?	vii
When may I exercise my SARs?	vii
How do I exercise my SARs?	vii
What happens if my service with PG&E Corporation terminates before my stock appreciation right vests?	vii
When do my SARs expire?	vii
Do I have any shareholder rights?	vii
Restricted Stock	vii
What is a restricted stock award?	vii
Will I be required to pay for a grant of restricted stock?	vii
When will restricted stock awards vest?	vii
What happens to restricted stock awards if my service with PG&E Corporation terminates before my Award vests?	viii
When will restricted stock awards be settled?	viii
Do I have any shareholder rights?	viii
Restricted Stock Units	viii
What are restricted stock units?	viii

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Will I be required to pay for a grant of restricted stock units?	viii
When will restricted stock units vest?	viii
What happens to restricted stock unit awards if my service with PG&E Corporation terminates before the scheduled vesting date?	viii
Will I receive dividends on restricted stock units?	viii
How soon will I receive the shares after the restricted stock units have vested?	ix
Do I have the same rights as other shareholders?	ix
Performance Awards	ix
What are performance awards?	ix
What are the performance measures and how do they work?	ix
When will performance awards vest?	ix
Termination of Service	ix
What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if my service is terminated?	ix
What happens to my stock options, SARS, restricted stock, performance awards, and restricted stock units if I retire?	x
Change in Control	x
What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if there is a “change in control” of PG&E Corporation?	x
What happens to my award if my service is terminated other than for cause in connection with a “change in control” of PG&E Corporation?	x
What would be considered a “change in control” of PG&E Corporation?	x
What happens to my award if I am terminated from my position with a subsidiary of PG&E Corporation as a result of the divestiture or change in control of the subsidiary?	xi
Transferability: Resale Restrictions	xi
May I transfer my stock options, SARS, restricted stock, restricted stock units, and performance awards to someone else?	xi
Are there any restrictions on my ability to sell common stock received when my awards are settled in shares of common stock or when I exercise my stock options?	xi
What if I am an executive officer of PG&E Corporation?	xi
Tax Consequences	xii
Are there any tax consequences when I am granted a nonqualified stock option or SARs?	xii
What are the tax consequences when I exercise my stock options or SARs?	xii
Will my exercise of a stock option or SAR be subject to tax withholding?	xii
What are the tax consequences if I sell the shares purchased upon exercise of a stock option?	xii
Are there any tax consequences when I am granted an incentive stock option?	xiii
What are the tax consequences when I exercise my incentive stock options?	xiii
What are the tax consequences if I sell the shares purchased upon exercise of an incentive stock option?	xiii
What if I make a qualifying disposition?	xiii
What if I make a disqualifying disposition?	xiii

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What are the tax consequences relating to restricted stock (including any Performance Share awards)?	xiii
What is a Section 83(b) election?	xiii
How are dividends and dividend equivalents related to my restricted stock awards taxed?	xiv
What are the tax consequences relating to restricted stock units (including Performance Units)?	xiv
How can I satisfy the amount of California SDI and FICA taxes that may be due before my restricted stock units are settled?	xiv
How can I satisfy the withholding taxes that arise when my restricted stock units vest?	xiv
What are the tax consequences if I sell shares I acquire upon vesting of restricted stock unit awards or settlement of my restricted stock units?	xiv
What is the impact of Section 409A of the Code on my awards?	xv
Additional Information about PG&E Corporation	xv

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Information about the LTIP

Administration of the LTIP.

The LTIP is administered by the Compensation Committee (the “Committee”) of the Board of Directors of PG&E Corporation (the “Company”). The Committee is composed entirely of directors who satisfy the definition of “independent director” set forth in PG&E Corporation’s Corporate Governance Guidelines and also meet the enhanced independence standards established by the New York Stock Exchange or any other applicable stock exchanges.

Generally, the Committee approves LTIP awards made to officers of PG&E Corporation and to officers of Pacific Gas and Electric Company and approves guidelines for LTIP awards to be made to certain other eligible participants during a particular year, including the amount and type of award, the terms and conditions of awards, and the aggregate value of awards. The Chief Executive Officer of PG&E Corporation has authority to implement the award guidelines approved by the Committee. The Committee may also (i) amend or modify awards in accordance with the terms of the LTIP, (ii) prescribe, amend or rescind rules relating to the LTIP, (iii) construe, interpret and reconcile any inconsistency regarding the LTIP and (iv) make all other determinations with respect to the LTIP, to the extent permitted by applicable law and subject to certain restrictions specified in the LTIP.

Eligibility.

Awards may be granted to employees, directors (including non-employee directors) and consultants of PG&E Corporation and certain subsidiaries, at the discretion of the Committee. Nothing in the LTIP or in any award agreement is intended to provide you with the right to remain in the service of the PG&E Corporation or any of its subsidiaries for any specific period.

Duration of the LTIP.

The LTIP will terminate on May 11, 2024, unless terminated sooner according to the terms of the LTIP.

Adjustment Upon Changes in Number or Value of Shares of Common Stock.

In the event of certain changes in PG&E Corporation common stock without receipt of consideration, such as stock dividends, stock splits, recapitalizations, mergers, consolidations and similar changes, or in the event of payment of certain non-stock dividends or distributions that have a material effect on the value of PG&E Corporation common stock, appropriate adjustments shall be made to the number and kind of shares subject to the LTIP and to any outstanding awards, the award limitations and in the exercise or purchase price per share under any outstanding awards in order to prevent dilution or enlargement of a participant’s right under the LTIP,subject to the provisions of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”).

Award Agreements.

    Awards granted under the LTIP will be evidenced by award agreements in a written or electronic form that will provide additional terms and conditions associated with such awards, as determined by the Committee.

Amendment and Termination of the LTIP and Incentive Awards.

The Board of Directors or the Committee may at any time suspend, terminate, modify, or amend the LTIP in any respect. However, shareholder approval of amendments shall be obtained in the manner and to the degree required by applicable laws or regulations, or the terms of the LTIP. The Committee also may amend or modify the terms and conditions of any incentive award granted under the LTIP, or extend, cancel or renew any grant of an award; provided that no such amendment, modification, cancellation, extension or renewal may, without your consent, adversely affect your rights under awards previously granted to you.

Withholding Taxes.

    You will be responsible for payment of any taxes or similar charges required by law to be paid or withheld with respect to any award, including with respect to the vesting, settlement and exercise of any award. Any required withholdings must be paid by you on or prior to the payment or other event that results in taxable income with respect to an award. The award agreement may specify the manner in

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which the withholding obligation shall be satisfied with respect to the particular type of award, which may include permitting you to elect to satisfy the withholding obligation by tendering shares of PG&E Corporation common stock to the PG&E Corporation or having the PG&E Corporation withhold a number of shares of common stock having a value equal to the minimum statutory tax or similar charge required to be paid or withheld.

Recoupment of Awards.

Awards are subject to recoupment in accordance with any applicable law and any recoupment policies, procedures, or requirements adopted by or applicable to the Corporation from time to time.

Miscellaneous.

The LTIP is generally not subject to the Employee Retirement Income Security Act of 1974 (ERISA) and it is not qualified under Section 401(a) of the Code.

Stock Options

What is a stock option?

A stock option allows you to buy a certain number of shares of PG&E Corporation common stock at a fixed price. The per share purchase price (or exercise price) generally will be equal to the closing price of PG&E Corporation common stock on the date on which the option is granted, unless otherwise specified in your award agreement.

Will I be required to pay for a grant of a stock option?

    Generally, no. It is anticipated that the grant of stock options would be made in recognition of your service to PG&E Corporation (or any of its subsidiaries) and would not require any cash payment. To purchase PG&E Corporation common stock underlying a stock option, however, you must exercise the stock option and pay the exercise price as described below and set forth in your award agreement.

When may I exercise my stock options?

You may not exercise your stock options until your right to do so has vested in accordance with the vesting terms that are determined when the stock options are granted and set forth in your award agreement governing your stock options. Vesting is generally contingent on your continued service to PG&E Corporation or its affiliates through the applicable vesting date. Stock options may also be subject to performance-based vesting measures that affect the number of options that you ultimately may be permitted to exercise. Please consult your award agreement for details regarding the vesting terms of your stock options.

How do I exercise my stock options?

You must deliver a completed electronic exercise election form to the record-keeper for the LTIP, which is currently Charles Schwab. Instructions for completing and submitting the form are available from the recordkeeper.

What happens if my service with PG&E Corporation ends before my stock option is fully vested and exercisable?

The award agreement describes what happens to the stock option if your service terminates before the stock option is fully vested and exercisable. In general, upon termination of service with PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested stock options.

When do my stock options expire?

Although the term of an option may vary, in general, the term of each stock option is 10 years, unless otherwise specified in your award agreement. The options generally will expire earlier upon or within a specified period following your termination of service.

Do I have any shareholder rights?

You will not have any rights of a shareholder with respect to the shares subject to the options unless an option is exercised and shares are issued to you.

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How do I pay for shares and taxes upon exercise of my stock options?

Unless your award agreement provides otherwise, you may pay the option exercise price and applicable tax withholdings using (1) cash, check or cash equivalent; (2) shares of PG&E Corporation common stock; (3) a "cashless exercise" procedure (whereby a broker sells a number of shares purchased upon exercise, with a value equal to the aggregate exercise price and applicable tax withholdings and remits the sale proceeds to PG&E Corporation to pay for the aggregate exercise price and applicable tax withholdings); (4) by surrendering a number of shares of PG&E Corporation common stock that otherwise would have been issued to you in connection with the stock option exercise, with an aggregate fair market value (as determined as of the business day before the date of exercise) equal to the aggregate exercise price and applicable tax withholdings, (5) by another method that pay be approved by the Committee or (6) any combination of the foregoing. If shares are used to pay all or part of the exercise price, the cash and any shares surrendered must have a fair market value (determined as of the business day before the date of exercise) that is not less than the applicable exercise price.

How is an incentive stock option different than a nonqualified stock option?    

An incentive stock option and a nonqualified stock option have different U.S. federal tax consequences, which are explained in more detail in the “Tax Consequences” section below. Each stock option will be designated by the Committee as either an incentive stock option or a nonqualified stock option and set forth in the Award Agreement evidencing the grant. If an option granted as an incentive stock option fails to qualify as an incentive stock option under the Code, it will be treated as a nonqualified stock option.

Stock Appreciation Rights

What is a stock appreciation right?

    A stock appreciation right (SAR) gives you the right to receive an amount equal to the excess of the fair market value of a share of common stock of PG&E Corporation on the date of exercise over a fixed value (the “Base Price”) of the SAR. A SAR may be settled in [shares of common stock, cash, or any combination thereof] as specified by the Committee. The Base Price of a SAR granted under the LTIP will not be less than the fair market value of the shares of common stock subject to the SAR on the date the SAR is granted.

Will I be required to pay for a grant of stock appreciation rights?

    Generally, no. It is anticipated that SARs would be granted in recognition of your service to PG&E Corporation (or any of its subsidiaries) and would not require any cash payment.

When may I exercise my SARs?

You may not exercise your SARs until your right to do so has vested in accordance with the vesting terms that are determined when the SARs are granted and set forth in your award agreement governing your SARs. Vesting is generally contingent on your continued service to PG&E Corporation or its affiliates through the applicable vesting date. SARs may also be subject to performance-based vesting measures that affect the number of SARs that you ultimately may be permitted to exercise. Please consult your award agreement for details regarding the vesting terms of your SARs.

How do I exercise my SARs?

    You must deliver a completed electronic exercise election form to the record-keeper for the LTIP, currently Charles Schwab. Instructions for completing and submitting the form are available from the recordkeeper

What happens if my service with PG&E Corporation terminates before my stock appreciation right vests?

    The award agreement describes what happens to the SARs if your service terminates before the SARs are fully vested and exercisable. In general upon termination of service with PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested SARs.

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When do my SARs expire?

    Although the term of an SAR may vary, in general, the term of each SAR is 10 years, unless otherwise specified in your award agreement. The SARs generally will expire earlier upon or within a specified period following termination of service.

Do I have any shareholder rights?

You will not have any rights of a shareholder with respect to the SARs unless shares subject to the SARs are issued to you in settlement of the SARs. However, if the SARs are settled in cash, you will not become a shareholder, even if the amount of cash payable is determined by reference to the value of shares of common stock.

Restricted Stock

What is a restricted stock award?

    A restricted stock award is a grant of shares of PG&E Corporation common stock that is subject to vesting.

Will I be required to pay for a grant of restricted stock?

    Generally, no. It is anticipated that restricted stock awards would be granted in recognition of your service to the PG&E Corporation (or any of its subsidiaries) and would not require any cash payment. However, in setting the terms of the grant, the Committee has the discretion to require payment.

When will restricted stock awards vest?

In order for your restricted stock awards to vest, you must generally remain in the service of PG&E Corporation during the vesting period. Vesting may also be contingent upon the achievement of specified performance conditions and/or such other terms and conditions determined by the Committee. Restricted stock awards that are subject to performance-based vesting terms are referred to as Performance Shares in the LTIP, and also may be called performance share units. The vesting terms of a restricted stock award will be set forth in your award agreement.

What happens to restricted stock awards if my service with PG&E Corporation terminates before my Award vests?

    The award agreement describes what happens to the restricted stock award if your service terminates before the restricted stock award is fully vested and transferable. In general upon termination of service with the PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested restricted stock awards.

When will restricted stock awards be settled?

When restrictions on the restricted stock award lapse (i.e., you vest) and you satisfy any other conditions imposed by the Committee pursuant to the LTIP or your award agreement, you will become the owner of unrestricted shares of common stock of PG&E Corporation.

Do I have any shareholder rights?

Unless otherwise provided in your award agreement, you will have all of the rights of a shareholder with respect to restricted stock during the applicable restricted period, including the right to receive payment of dividends and distributions with respect to the underlying shares of PG&E Corporation common stock (which will be subject to the same vesting terms as the underlying shares of common stock).

Restricted Stock Units

What are restricted stock units?

A restricted stock unit is a right to receive shares of PG&E Corporation common stock when the restricted stock units are settled following vesting. PG&E Corporation common stock is not issued at the time of grant of a restricted stock unit award.

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Will I be required to pay for a grant of restricted stock units?

Generally, no. It is anticipated that restricted stock unit awards would be granted in recognition of your service to the PG&E Corporation (or any of its subsidiaries) and would not require any cash payment. However, in setting the terms of the grant, the Committee has the discretion to require payment.

When will restricted stock units vest?

In order for your restricted stock awards to vest, you must generally remain in the service of PG&E Corporation during the vesting period. Vesting may also be contingent upon the achievement of specified performance conditions and/or such other terms and conditions determined by the Committee. Restricted stock unit awards that are subject to performance-based vesting terms are referred to as Performance Shares in the LTIP. The vesting terms of a restricted stock award will be set forth in your award agreement.

What happens to restricted stock unit awards if my service with PG&E Corporation terminates before the scheduled vesting date?

    Your award agreement describes what happens to the restricted stock unit if your service terminates before the scheduled vesting date. In general, upon termination of service with the PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested restricted stock units.

Will I receive dividends on restricted stock units?

The Committee may provide in an award agreement that you will be entitled to receive dividend equivalents with respect to the payment of cash dividends, which, unless otherwise provided in an award agreement, will be credited to you in the form of additional whole restricted stock units as of the date of payment of such cash dividends on PG&E Corporation common stock. The number of additional restricted stock units (rounded to the nearest whole number) to be credited shall be determined by dividing the amount of cash dividends paid on such date with respect to the number of shares of common stock represented by the restricted stock units previously granted to you, by the fair market value of a share of common stock on such date. Settlement of dividend equivalents will be made in the same manner as the restricted stock units, which may include cash, shares of common stock of PG&E Corporation or a combination thereof.

How soon will I receive the shares after the restricted stock units have vested?     

PG&E Corporation will generally issue shares of PG&E Corporation common stock in respect of your restricted stock units within 60 days after the restricted stock units vest but no later than March 15 of the year following the year in which any applicable performance period ends or at such other times as set forth in your award agreement. However, the Committee may also settle restricted stock units in cash or a combination of cash and shares of common stock.

PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies). In such event, any shares of common stock to which you would otherwise be entitled during the six-month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.

Do I have the same rights as other shareholders?

You will not have voting rights with respect to the restricted stock units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).

Performance Awards

What are performance awards?

Performance awards may be in the form of Performance Shares or Performance Units (each as may be described above) and are awards that are eligible to vest based on the achievement of performance measures at the end of a pre-established performance period (“Performance Period”), as set forth in your

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award agreement. Participants may receive one or more grants of performance awards, and each grant may reference one or more performance measures.

What are the performance measures and how do they work?

    A description of the applicable performance measures and how they work can be found in your award agreement.

When will performance awards vest?

Except as otherwise set forth in your ward agreement, vesting will occur following the Committee’s certification of the extent to which the performance goals applicable to each type of performance measure are achieved. Certification will occur after the completion of the relevant Performance Period.

Termination of Service

What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if my service is terminated?

In general, and unless otherwise specified in your award agreement, upon your voluntary termination of service with PG&E Corporation (other than retirement, if provided for in your award agreement), your termination of service with or without cause, or your death or disability, you will forfeit (1) any awards that have not yet vested and (2) any associated accrued dividends. Vested options generally must be exercised within 30 days or the remaining term of the stock options, whichever is shorter.

What happens to my stock options, SARS, restricted stock, performance awards, and restricted stock units if I retire?

If applicable, your award agreement will provide for the treatment of awards in the case of retirement.

Change in Control

What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if there is a “change in control” of PG&E Corporation?

In general, and unless otherwise specified in your award agreement, in the event of a “change in control” (as defined in the LTIP), the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (“Acquiror”), may, without your consent, either assume or continue your outstanding award or the Acquiror may provide substantially equivalent awards in substitution for those awards.

In general, and unless otherwise specified in your award agreement, if the Acquiror does not assume or continue your outstanding award or if the Acquiror does not provide substantially equivalent awards, then your awards will become fully vested, and your options and SARs become exercisable immediately prior to the “change in control.”

What happens to my award if my service is terminated other than for cause in connection with a “change in control” of PG&E Corporation?

Your award agreement describes what happens to your award upon termination of your service by PG&E Corporation other than for cause in connection with a “change in control.”

What would be considered a “change in control” of PG&E Corporation?

The LTIP defines the term “change in control.” A change in control of PG&E Corporation occurs when:

•Any person becomes the beneficial owner of securities of PG&E Corporation representing 30% or more of the combined voting power of PG&E Corporation’s then outstanding securities;

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•If during any two consecutive years the directors at the beginning of the two-year period cease to be a majority of the Board of Directors at the end of the period, unless the election, or the nomination for election by the shareholders, of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were either (a) directors at the beginning of the two-year period or (b) were previously elected or nominated by at least two-thirds of the directors in office at the time of the individual director’s election or nomination;

•A consolidation or merger of PG&E Corporation is consummated and results in the former PG&E Corporation shareholders owning less than 70% of the voting power in the surviving entity (or parent of the surviving entity);

•Any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of PG&E Corporation is consummated; or

•The shareholders of PG&E Corporation approve a plan of liquidation or dissolution of PG&E Corporation.

What happens to my award if I am terminated from my position with a subsidiary of PG&E Corporation as a result of the divestiture or change in control of the subsidiary?

Your award agreement describes what happens to your award upon termination of your position by a subsidiary of PG&E Corporation as a result of a divestiture or “change in control” of the subsidiary.

Transferability: Resale Restrictions

May I transfer my stock options, SARS, restricted stock, restricted stock units, and performance awards to someone else?

Unless otherwise specified in your award agreement in accordance with the terms of the LTIP, you may not transfer your stock options, SARS, restricted stock, performance awards, or restricted stock units during your lifetime other than pursuant to a qualified domestic relations order (QDRO) or similar court order.After your death, your awards may be transferred in accordance withyour will or in accordance with the laws of descent and distribution. Except for options that may have been transferred as described above, your options may be exercised during your lifetime only by you, your duly appointed legal representative, or the person named in a QDRO.

Are there any restrictions on my ability to sell common stock received when my awards are settled in shares of common stock or when I exercise my stock options?

You are free to sell your stock at any time, except when you are subject to a trading blackout or while you are in possession of nonpublic material information about PG&E Corporation or any of its subsidiaries. Confidential, nonpublic information should be considered material if there is substantial likelihood that a reasonable investor would consider the information important. You are prohibited by securities laws and by PG&E Corporation’s and Pacific Gas and Electric Company’s Insider Trading Policy from trading in securities of PG&E Corporation or Pacific Gas and Electric Company until the information has been disclosed and widely disseminated to the investing public, typically two full trading days following such disclosure. Also, if as determined by PG&E Corporation, your position exposes you to nonpublic material information, you may be temporarily prohibited from trading shares. You will be notified if this “blackout” period applies to you.

What if I am an executive officer of PG&E Corporation?

If you are an executive officer of PG&E Corporation or Pacific Gas and Electric Company, you will be prohibited from engaging in transactions involving securities of PG&E Corporation or Pacific Gas and Electric Company during quarterly blackout periods and you will be subject to the other conditions of PG&E Corporation’s and Pacific Gas and Electric Company’s Insider Trading Policy (in particular, requiring 10b5-1 plans for your transactions in PG&E shares subject to this prospectus). Executive officers of PG&E Corporation will be considered “affiliates” of PG&E Corporation (along with their spouses and other relatives sharing the same household). In general, if you are an affiliate of PG&E Corporation, your sales of shares must comply with SEC Rule 144. In addition, executive officers of PG&E Corporation and Pacific Gas and Electric Company are subject to the reporting and short-swing profit liability provisions of Section 16 of the Securities Exchange Act of 1934 Act with respect to their

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transactions in PG&E Corporation common stock and Pacific Gas and Electric Company preferred securities, respectively. Information regarding Rule 144 and Section 16 is available from the Corporate Secretary.

In addition, you will not be able to buy or sell your shares if you are subject to the trading restrictions imposed by the Sarbanes Oxley Act of 2002 in connection with a blackout period under a PG&E Corporation sponsored retirement plan.

Tax Consequences

    The following is a general description of the United States federal income tax consequences relating to your awards under the Code as currently in effect and is not intended to be a complete description of all the possible tax consequences. Federal tax treatment may change should the Code be amended. The consequences may differ based on your personal situation. PG&E Corporation cannot assure you of any particular tax result and is not providing you with tax advice. If you have any questions regarding the tax consequences of receiving a grant of stock options, SARS, restricted stock, restricted stock units, and performance awards you should contact your tax advisor. PG&E Corporation makes no representation that the LTIP will comply with Section 409A and makes no undertaking to prevent Section 409A from applying to the LTIP or any award or to mitigate its effects on any award.

You will be required to pay to PG&E Corporation, or to make arrangements satisfactory to PG&E Corporation for the payment of withholding taxes, including social security and Medicare taxes due under the Federal Insurance Contributions Act (FICA), and the California State Disability Insurance (SDI) tax that become due in connection with your awards. PG&E Corporation’s obligations under the LTIP and your award agreement are subject to payment of, or to the arrangement for payment of, all withholding taxes. PG&E Corporation will have the right, to the extent permitted by law, to deduct any such withholding taxes from any payment of any kind otherwise due to you.

Are there any tax consequences when I am granted a nonqualified stock option or SARs?

In general, there are no immediate federal income tax consequences when you are granted nonqualified stock options or SARs.

What are the tax consequences when I exercise my stock options or SARs?

When you exercise a nonqualified stock option or SAR, you generally will have taxable ordinary income equal to the difference between the current fair market value of the shares of common stock and the exercise price or base price. The amount of ordinary income will be included in your W-2 form for the year in which you exercised your stock option or SAR.

Will my exercise of a stock option or SAR be subject to tax withholding?

Yes. In connection with the exercise of a nonqualified stock option or SAR, PG&E Corporation will be required to withhold applicable taxes on income you recognize upon the exercise. Please see your award agreement for the methods by which you may satisfy the applicable withholding taxes.

What are the tax consequences if I sell the shares purchased upon exercise of a stock option?

If you sell the shares you purchased upon exercise of your nonqualified stock options you will be taxed on the excess of the sale price over the market value of the shares on the exercise date (your tax basis). (The market value of the shares on the date of exercise will be the sum of the option exercise price plus the amount of ordinary income you recognized when the option was exercised.) Whether or not this amount can be treated as long-term capital gain (or loss) depends on the length of time you held the shares before selling them. Currently, to receive long-term capital gain treatment you must hold the stock for more than one year. If you are subject to alternative minimum tax, you should consult your tax advisor.

If you paid the option exercise price by delivering shares you already owned, then the tax consequences upon sale of the shares are slightly different. Your tax basis in the surrendered shares and the length of time (the holding period) that you held the surrendered shares will be carried over to an equal number of shares that you acquired upon exercise. If you purchased more shares than the number

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of shares you delivered, the holding period for the excess shares will start on the date of exercise and the price of such shares will be equal to the market value of the shares on the date of exercise.

Are there any tax consequences when I am granted an incentive stock option?

In general, there are no immediate federal income tax consequences when you are granted incentive stock options.

What are the tax consequences when I exercise my incentive stock options?

You will not recognize any taxable income, for regular income tax purposes, at the time an incentive stock option is exercised. However, the amount by which the fair market value (at the time of exercise) of the purchased shares exceeds the exercise price paid for those shares will constitute an adjustment to your income for purposes of the alternative minimum tax.

What are the tax consequences if I sell the shares purchased upon exercise of an incentive stock option?

    The federal income tax liability will depend upon whether you make a qualifying or disqualifying disposition of the shares purchased under the incentive stock option. Subject to certain requirements in the Code, a qualifying disposition will occur if the sale or other disposition of shares takes place more than two years after the date the incentive stock option was granted and more than one year after the date that the stock option was exercised for the particular shares involved in the disposition. A disqualifying disposition is any sale or other disposition made before both of these requirements are satisfied.

What if I make a qualifying disposition?

    You will recognize a long-term capital gain equal to the excess of (a) the amount realized upon the sale or other disposition over (b) the exercise price paid for the shares. You will recognize a long-term capital loss if the amount realized is lower than the exercise price paid for the shares.

What if I make a disqualifying disposition?

    If you dispose of shares before the minimum holding periods described above have been satisfied, you will recognize ordinary income at the time of the disposition in an amount equal to the fair market value of the shares on the exercise date over the exercise price paid for those shares. Any additional gain recognized on the disqualifying disposition will be taxable at capital gains rates (long-term if the shares have been held for more than one year following the exercise date of the option). If the sale proceeds from a disqualifying disposition are less than the fair market value of the shares on the date of exercise, any ordinary income recognized is limited to the gain (if any) realized on the sale.

What are the tax consequences relating to restricted stock (including any Performance Share awards)?

    You will not recognize income until the transfer restrictions and forfeiture provisions lapse (i.e., you vest) unless you voluntarily elect to recognize income on the date of grant by filing an election under Section 83(b) of the Code. If you do not make a Section 83(b) election, then at the time that the transfer restrictions and forfeiture provisions lapse, you will recognize as ordinary income an amount equal to the excess of the fair market value of the shares on the date of lapse over the purchase price (if any) paid for such shares.

What is a Section 83(b) election?

    A Section 83(b) election is available only for awards of restricted stock (including performance shares). Section 83(b) allows you to recognize ordinary income on the fair market value of the restricted stock on the date of grant instead of on the date the award vests. Thereafter, any further gain or loss recognized upon the ultimate sale or disposition of the restricted stock is treated as capital gain or loss. Section 83(b) elections may be made with respect to restricted stock awards, to the extent permitted by the Committee.

How are dividends and dividend equivalents related to my restricted stock awards taxed?

Any dividends received with respect to a restricted stock award will be subject to the same vesting terms as the related restricted stock award. If you do not make a Section 83(b) election, you will not recognize ordinary income with respect to the dividends until the related restricted stock award vests (and therefore the dividends vest).

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What are the tax consequences relating to restricted stock units (including Performance Units)?

You will not recognize income until the restricted stock units are settled. Generally, when your restricted stock units are settled after vesting, you will have taxable ordinary income in the amount of the fair market value of the shares received in connection with the settlement of the restricted stock units and you will be required to satisfy applicable withholding taxes.

In the following situations you may be required to satisfy FICA and California SDI taxes even though the restricted stock units have not yet been settled:

•If you are retirement-eligible on the date of the award (if your award agreement provides for continued vesting after retirement),

•When you become “retirement-eligible,” if your award agreement provides for continued vesting after retirement,

•If your service is terminated other than for cause (as described in your award agreement), or

•Any other situations under which your restricted stock units vest before they are settled.

How can I satisfy the amount of California SDI and FICA taxes that may be due before my restricted stock units are settled?

Under these circumstances FICA and California SDI taxes must be paid either by check payable to PG&E Corporation or through payroll deductions. Unless you deliver a check to PG&E Corporation, the amount will be satisfied through payroll deductions.

How can I satisfy the withholding taxes that arise when my restricted stock units vest?

    You must arrange to pay the withholding taxes that arise when your restricted stock units vest in a manner acceptable to PG&E Corporation. PG&E Corporation may withhold from the shares otherwise issuable to you in settlement of restricted stock units a number of whole shares having a fair market value, as determined by PG&E Corporation, equal to the applicable withholding taxes. The remaining number of whole shares will be issued to you.

What are the tax consequences if I sell shares I acquire upon vesting of restricted stock unit awards or settlement of my restricted stock units?    

If you recognize gain when you sell shares your gain will be taxable at long-term or short-term capital gain rates. If you recognize a loss, it will be a capital loss. The amount of your gain or loss will be the difference between the amount you receive on the sale of the shares and the value used to calculate the applicable withholding taxes when your award was settled. Whether your gain or loss is long-term or short-term will depend on whether you have held your shares for more than one year. The holding period generally begins at the time your performance awards or restricted stock units are settled or stock options are exercised, and shares are issued to you.

What is the impact of Section 409A of the Code on my awards?

    If an award is treated as “nonqualified deferred compensation” and the award does not comply with or is not exempt from Section 409A, Section 409A may impose additional taxes, interest and penalties on you. All grants made under the LTIP are designed and intended to either be exempt from or comply with Section 409A to avoid such additional taxes, interest and penalties. Neither the Committee nor PG&E Corporation is obligated to ensure that awards comply with Section 409A or to take any actions to ensure such compliance.

Additional Information about PG&E Corporation

PG&E Corporation has filed a registration statement relating to the offer and sale of its shares of common stock under the LTIP with the Securities and Exchange Commission (SEC). The following documents filed by PG&E Corporation with the SEC are incorporated by reference into the registration statement and into this prospectus:

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•The annual report on Form 10-K of PG&E Corporation;

•Quarterly reports on Form 10-Q and Current Reports on Form 8-K;

•All other documents filed with the SEC pursuant to Section 13(a), 13(c), 14 and 15(a) of the Securities Exchange Act of 1934, as amended; and

•The description of PG&E Corporation common stock filed with the SEC, including any amendment or report filed for the purpose of updating such description.

All documents filed with the SEC by PG&E Corporation after the date the registration statement was filed and before the filing of a post-effective amendment to the registration statement that indicates all securities offered under the LTIP have been sold or deregisters all securities then remaining unsold, will also be incorporated by reference in this summary and deemed to be a part of this summary as of the date such documents are filed with the SEC.

Copies of the documents listed above (other than exhibits to such documents), and copies of PG&E Corporation’s latest annual report to shareholders, proxy statement, reports, and other communications sent to shareholders, will be sent to you without charge upon your request. Requests may be directed to:

Office of the Corporate Secretary

PG&E Corporation

77 Beale Street    P.O. Box 770000

San Francisco, California 94177

(Telephone: 415-973-8200)

These reports are also available through PG&E Corporation’s website at www.pgecorp.com, through the SEC’s website at www.sec.gov, and through various financial websites.

PG&E Corporation’s filings with the SEC, including its Annual Report on Form 10-K are available on PG&E Corporation’s website at www.pgecorp.com under the “Investors” link. (Click on “Financial Reports” and then click on “SEC Filings.”)

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EX-10.93

EXHIBIT 10.93

PG&E CORPORATION
2021 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below (sometimes referred to as “you”). The Restricted Stock Units have been granted under the PG&E Corporation 2021 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the “Agreement”).

Date of Grant:     June 01, 2021

Name of Recipient:     Carla Peterman    

Recipient’s Participant ID:     XXXXXXXX    

Number of Restricted Stock Units:     26,601    

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this award, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated June 2021.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar days of the date of this award at ATTN: LTIP Administrator, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, 94105.

Attachment

PG&E CORPORATION
2021 LONG-TERM INCENTIVE PLAN

NON-ANNUAL RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements

This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LTIP. In the event of any conflict between the provisions of this Agreement or the above cover sheet and the PG&E Corporation 2012 Officer Severance Policy, this Agreement or the above cover sheet will govern, as applicable. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group.

Grant of Restricted Stock Units

PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.

Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, the total number of Restricted Stock Units originally subject to this Agreement, as shown on the cover sheet, will vest in accordance with the below vesting schedule (the “Normal Vesting Schedule”). 13,300 on June 01, 2022 13,301 on June 01, 2023 The amounts payable upon each vesting date are hereby designated separate payments for purposes of Section 409A of the Internal Revenue Code of 1986, as amended (“Code”). Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment will then be cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event that cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the RSUs are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation will issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance will, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death, or (3) “separation from service,” within the meaning of Code Section 409A within 2 years following a Change in Control.

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Voluntary Termination	In the event of your voluntary termination (other than Retirement), all unvested Restricted Stock Units will be cancelled on the date of termination.
Retirement	In the event of your Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such Retirement had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however, that in the event of your Retirement within 2 years following a Change in Control, those Restricted Stock Units that would have vested within 12 months following such Retirement will be vested and settled as soon as practicable after (but not later than 60 days after) the date of such Retirement. All other unvested Restricted Stock Units will be cancelled. Your voluntary termination of employment will be considered Retirement if you are age 55 or older on the date of termination (other than termination for cause) and if you were employed by PG&E Corporation for at least eight consecutive years ending on the date of termination of your employment.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense, or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation. For the avoidance of doubt, you will not be eligible to retire if your employment is being or is terminated for cause.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause or Retirement, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.

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Death/Disability	In the event of your death or Disability (as defined in Code Section 409A) while you are employed, all of your Restricted Stock Units will vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder will be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	If your employment is terminated (other than for cause, or your voluntary termination, or your Retirement] (1) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Code Section 424(f), or (2) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, then your Restricted Stock Units will vest and be settled in the same manner as for a “Termination other than for Cause” described above.
Change in Control	In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither so assumed nor so continued by the Acquiror, and the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units will vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.

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Termination In Connection with a Change in Control

If you separate from service (other than termination for cause, or your voluntary termination, or your Retirement) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) will vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement. In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this award) will vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.

Delay

PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Code Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.

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Withholding Taxes

The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.

Leaves of Absence

For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you will be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence will be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.

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Voting and Other Rights	You will not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent). No Restricted Stock Units and no shares of Stock that have not been issued hereunder may be sold, assigned, transferred, pledged, or otherwise encumbered, other than by will or the laws of decent and distribution, and the Restricted Stock Units may be exercised during the life of the Recipient only by the Recipient or the Recipient’s guardian or legal representative.
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Recoupment of Awards	Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time, including provisions of the Officer Severance Policy, and provisions of the PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy, as last revised on February 19, 2019 and available on the PG&E@Work internet site for the Long-Term Incentive Plan (the policy and location may be changed from time to time by PG&E Corporation).
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

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PG&E CORPORATION

2014 LONG-TERM INCENTIVE PLAN

A total of 47,000,000 shares of PG&E Corporation common stock (“Shares”), no par value, are available for issuance under the PG&E Corporation 2014 Long-Term Incentive Plan, as may be amended (LTIP), less the number of Shares covered by awards granted under the PG&E Corporation 2006 Long-Term Incentive Plan after December 31, 2013, but prior to the effective date of the LTIP, and determined in accordance with Section 4.1 of the LTIP. The Shares will come from PG&E Corporation’s authorized, but unissued, shares of common stock and/or Shares reacquired by PG&E Corporation on the open market for this purpose. The purpose of the LTIP is to advance the interests of PG&E Corporation and its shareholders by providing officers, key management employees, and other eligible participants with financial incentives tied directly to PG&E Corporation's long-term business objectives. Awards granted under the LTIP can include stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, performance shares, performance units, deferred compensation awards, and other stock-based awards.

This summary describes the stock options, SARs, restricted stock, performance awards, and restricted stock units which may be granted under the LTIP. This summary does not purport to be complete, and is qualified in its entirety by reference to the LTIP and your award agreement evidencing an award. The terms of the LTIP will govern in case there is any conflict with any part of this summary or your individual award agreement. Certain terms of stock options, SARS, restricted stock, restricted stock units, and performance awards differ from those described in this summary and such terms will be set forth in your award agreement governing such award. You may obtain a copy of the LTIP by calling or writing the LTIP Administrator, Pacific Gas and Electric Company, 245 Market Street, N2T, San Francisco, CA 94105, (415) 266-8644.

______________________________

THIS DOCUMENT CONSTITUTES PART OF A PROSPECTUS COVERING SECURITIES THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933.

March 2021

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Contents

Information about the LTIP	iv
Administration of the LTIP.	iv
Eligibility.	iv
Duration of the LTIP.	iv
Adjustment Upon Changes in Number or Value of Shares of Common Stock.	iv
Award Agreements.	iv
Amendment and Termination of the LTIP and Incentive Awards.	iv
Withholding Taxes.	v
Recoupment of Awards.	v
Miscellaneous.	v
Stock Options	v
What is a stock option?	v
Will I be required to pay for a grant of a stock option?	v
When may I exercise my stock options?	v
How do I exercise my stock options?	v
What happens if my service with PG&E Corporation ends before my stock option is fully vested and exercisable?	vi
When do my stock options expire?	vi
Do I have any shareholder rights?	vi
How do I pay for shares and taxes upon exercise of my stock options?	vi
How is an incentive stock option different than a nonqualified stock option?	vi
Stock Appreciation Rights	vi
What is a stock appreciation right?	vi
Will I be required to pay for a grant of stock appreciation rights?	vii
When may I exercise my SARs?	vii
How do I exercise my SARs?	vii
What happens if my service with PG&E Corporation terminates before my stock appreciation right vests?	vii
When do my SARs expire?	vii
Do I have any shareholder rights?	vii
Restricted Stock	vii
What is a restricted stock award?	vii
Will I be required to pay for a grant of restricted stock?	vii
When will restricted stock awards vest?	vii
What happens to restricted stock awards if my service with PG&E Corporation terminates before my Award vests?	viii
When will restricted stock awards be settled?	viii
Do I have any shareholder rights?	viii
Restricted Stock Units	viii
What are restricted stock units?	viii
Will I be required to pay for a grant of restricted stock units?	viii
When will restricted stock units vest?	viii

What happens to restricted stock unit awards if my service with PG&E Corporation terminates before the scheduled vesting date?	viii
Will I receive dividends on restricted stock units?	viii
How soon will I receive the shares after the restricted stock units have vested?	ix
Do I have the same rights as other shareholders?	ix
Performance Awards	ix
What are performance awards?	ix
What are the performance measures and how do they work?	ix
When will performance awards vest?	ix
Termination of Service	ix
What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if my service is terminated?	ix
What happens to my stock options, SARS, restricted stock, performance awards, and restricted stock units if I retire?	x
Change in Control	x
What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if there is a “change in control” of PG&E Corporation?	x
What happens to my award if my service is terminated other than for cause in connection with a “change in control” of PG&E Corporation?	x
What would be considered a “change in control” of PG&E Corporation?	x
What happens to my award if I am terminated from my position with a subsidiary of PG&E Corporation as a result of the divestiture or change in control of the subsidiary?	xi
Transferability: Resale Restrictions	xi
May I transfer my stock options, SARS, restricted stock, restricted stock units, and performance awards to someone else?	xi
Are there any restrictions on my ability to sell common stock received when my awards are settled in shares of common stock or when I exercise my stock options?	xi
What if I am an executive officer of PG&E Corporation?	xi
Tax Consequences	xii
Are there any tax consequences when I am granted a nonqualified stock option or SARs?	xii
What are the tax consequences when I exercise my stock options or SARs?	xii
Will my exercise of a stock option or SAR be subject to tax withholding?	xii
What are the tax consequences if I sell the shares purchased upon exercise of a stock option?	xii
Are there any tax consequences when I am granted an incentive stock option?	xiii
What are the tax consequences when I exercise my incentive stock options?	xiii
What are the tax consequences if I sell the shares purchased upon exercise of an incentive stock option?	xiii
What if I make a qualifying disposition?	xiii
What if I make a disqualifying disposition?	xiii
What are the tax consequences relating to restricted stock (including any Performance Share awards)?	xiii
What is a Section 83(b) election?	xiii
How are dividends and dividend equivalents related to my restricted stock awards taxed?	xiv
What are the tax consequences relating to restricted stock units (including Performance Units)?	xiv

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How can I satisfy the amount of California SDI and FICA taxes that may be due before my restricted stock units are settled?	xiv
How can I satisfy the withholding taxes that arise when my restricted stock units vest?	xiv
What are the tax consequences if I sell shares I acquire upon vesting of restricted stock unit awards or settlement of my restricted stock units?	xiv
What is the impact of Section 409A of the Code on my awards?	xv
Additional Information about PG&E Corporation	xv

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Information about the LTIP

Administration of the LTIP.

The LTIP is administered by the Compensation Committee (the “Committee”) of the Board of Directors of PG&E Corporation (the “Company”). The Committee is composed entirely of directors who satisfy the definition of “independent director” set forth in PG&E Corporation’s Corporate Governance Guidelines and also meet the enhanced independence standards established by the New York Stock Exchange or any other applicable stock exchanges.

Generally, the Committee approves LTIP awards made to officers of PG&E Corporation and to officers of Pacific Gas and Electric Company and approves guidelines for LTIP awards to be made to certain other eligible participants during a particular year, including the amount and type of award, the terms and conditions of awards, and the aggregate value of awards. The Chief Executive Officer of PG&E Corporation has authority to implement the award guidelines approved by the Committee. The Committee may also (i) amend or modify awards in accordance with the terms of the LTIP, (ii) prescribe, amend or rescind rules relating to the LTIP, (iii) construe, interpret and reconcile any inconsistency regarding the LTIP and (iv) make all other determinations with respect to the LTIP, to the extent permitted by applicable law and subject to certain restrictions specified in the LTIP.

Eligibility.

Awards may be granted to employees, directors (including non-employee directors) and consultants of PG&E Corporation and certain subsidiaries, at the discretion of the Committee. Nothing in the LTIP or in any award agreement is intended to provide you with the right to remain in the service of the PG&E Corporation or any of its subsidiaries for any specific period.

Duration of the LTIP.

The LTIP will terminate on May 11, 2024, unless terminated sooner according to the terms of the LTIP.

Adjustment Upon Changes in Number or Value of Shares of Common Stock.

In the event of certain changes in PG&E Corporation common stock without receipt of consideration, such as stock dividends, stock splits, recapitalizations, mergers, consolidations and similar changes, or in the event of payment of certain non-stock dividends or distributions that have a material effect on the value of PG&E Corporation common stock, appropriate adjustments shall be made to the number and kind of shares subject to the LTIP and to any outstanding awards, the award limitations and in the exercise or purchase price per share under any outstanding awards in order to prevent dilution or enlargement of a participant’s right under the LTIP,subject to the provisions of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”).

Award Agreements.

    Awards granted under the LTIP will be evidenced by award agreements in a written or electronic form that will provide additional terms and conditions associated with such awards, as determined by the Committee.

Amendment and Termination of the LTIP and Incentive Awards.

The Board of Directors or the Committee may at any time suspend, terminate, modify, or amend the LTIP in any respect. However, shareholder approval of amendments shall be obtained in the manner and to the degree required by applicable laws or regulations, or the terms of the LTIP. The Committee also may amend or modify the terms and conditions of any incentive award granted under the LTIP, or extend, cancel or renew any grant of an award; provided that no such amendment, modification, cancellation, extension or renewal may, without your consent, adversely affect your rights under awards previously granted to you.

Withholding Taxes.

    You will be responsible for payment of any taxes or similar charges required by law to be paid or withheld with respect to any award, including with respect to the vesting, settlement and exercise of any award. Any required withholdings must be paid by you on or prior to the payment or other event that results in taxable income with respect to an award. The award agreement may specify the manner in which the withholding obligation shall be satisfied with respect to the particular type of award, which may include permitting you to elect to satisfy the withholding obligation by tendering shares of PG&E Corporation common stock to the PG&E Corporation or having the PG&E Corporation withhold a

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number of shares of common stock having a value equal to the minimum statutory tax or similar charge required to be paid or withheld.

Recoupment of Awards.

Awards are subject to recoupment in accordance with any applicable law and any recoupment policies, procedures, or requirements adopted by or applicable to the Corporation from time to time.

Miscellaneous.

The LTIP is generally not subject to the Employee Retirement Income Security Act of 1974 (ERISA) and it is not qualified under Section 401(a) of the Code.

Stock Options

What is a stock option?

A stock option allows you to buy a certain number of shares of PG&E Corporation common stock at a fixed price. The per share purchase price (or exercise price) generally will be equal to the closing price of PG&E Corporation common stock on the date on which the option is granted, unless otherwise specified in your award agreement.

Will I be required to pay for a grant of a stock option?

    Generally, no. It is anticipated that the grant of stock options would be made in recognition of your service to PG&E Corporation (or any of its subsidiaries) and would not require any cash payment. To purchase PG&E Corporation common stock underlying a stock option, however, you must exercise the stock option and pay the exercise price as described below and set forth in your award agreement.

When may I exercise my stock options?

You may not exercise your stock options until your right to do so has vested in accordance with the vesting terms that are determined when the stock options are granted and set forth in your award agreement governing your stock options. Vesting is generally contingent on your continued service to PG&E Corporation or its affiliates through the applicable vesting date. Stock options may also be subject to performance-based vesting measures that affect the number of options that you ultimately may be permitted to exercise. Please consult your award agreement for details regarding the vesting terms of your stock options.

How do I exercise my stock options?

You must deliver a completed electronic exercise election form to the record-keeper for the LTIP, which is currently Charles Schwab. Instructions for completing and submitting the form are available from the recordkeeper.

What happens if my service with PG&E Corporation ends before my stock option is fully vested and exercisable?

The award agreement describes what happens to the stock option if your service terminates before the stock option is fully vested and exercisable. In general, upon termination of service with PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested stock options.

When do my stock options expire?

Although the term of an option may vary, in general, the term of each stock option is 10 years, unless otherwise specified in your award agreement. The options generally will expire earlier upon or within a specified period following your termination of service.

Do I have any shareholder rights?

You will not have any rights of a shareholder with respect to the shares subject to the options unless an option is exercised and shares are issued to you.

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How do I pay for shares and taxes upon exercise of my stock options?

Unless your award agreement provides otherwise, you may pay the option exercise price and applicable tax withholdings using (1) cash, check or cash equivalent; (2) shares of PG&E Corporation common stock; (3) a "cashless exercise" procedure (whereby a broker sells a number of shares purchased upon exercise, with a value equal to the aggregate exercise price and applicable tax withholdings and remits the sale proceeds to PG&E Corporation to pay for the aggregate exercise price and applicable tax withholdings); (4) by surrendering a number of shares of PG&E Corporation common stock that otherwise would have been issued to you in connection with the stock option exercise, with an aggregate fair market value (as determined as of the business day before the date of exercise) equal to the aggregate exercise price and applicable tax withholdings, (5) by another method that pay be approved by the Committee or (6) any combination of the foregoing. If shares are used to pay all or part of the exercise price, the cash and any shares surrendered must have a fair market value (determined as of the business day before the date of exercise) that is not less than the applicable exercise price.

How is an incentive stock option different than a nonqualified stock option?    

An incentive stock option and a nonqualified stock option have different U.S. federal tax consequences, which are explained in more detail in the “Tax Consequences” section below. Each stock option will be designated by the Committee as either an incentive stock option or a nonqualified stock option and set forth in the Award Agreement evidencing the grant. If an option granted as an incentive stock option fails to qualify as an incentive stock option under the Code, it will be treated as a nonqualified stock option.

Stock Appreciation Rights

What is a stock appreciation right?

    A stock appreciation right (SAR) gives you the right to receive an amount equal to the excess of the fair market value of a share of common stock of PG&E Corporation on the date of exercise over a fixed value (the “Base Price”) of the SAR. A SAR may be settled in [shares of common stock, cash, or any combination thereof] as specified by the Committee. The Base Price of a SAR granted under the LTIP will not be less than the fair market value of the shares of common stock subject to the SAR on the date the SAR is granted.

Will I be required to pay for a grant of stock appreciation rights?

    Generally, no. It is anticipated that SARs would be granted in recognition of your service to PG&E Corporation (or any of its subsidiaries) and would not require any cash payment.

When may I exercise my SARs?

You may not exercise your SARs until your right to do so has vested in accordance with the vesting terms that are determined when the SARs are granted and set forth in your award agreement governing your SARs. Vesting is generally contingent on your continued service to PG&E Corporation or its affiliates through the applicable vesting date. SARs may also be subject to performance-based vesting measures that affect the number of SARs that you ultimately may be permitted to exercise. Please consult your award agreement for details regarding the vesting terms of your SARs.

How do I exercise my SARs?

    You must deliver a completed electronic exercise election form to the record-keeper for the LTIP, currently Charles Schwab. Instructions for completing and submitting the form are available from the recordkeeper

What happens if my service with PG&E Corporation terminates before my stock appreciation right vests?

    The award agreement describes what happens to the SARs if your service terminates before the SARs are fully vested and exercisable. In general upon termination of service with PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested SARs.

When do my SARs expire?

    Although the term of an SAR may vary, in general, the term of each SAR is 10 years, unless otherwise specified in your award agreement. The SARs generally will expire earlier upon or within a specified period following termination of service.

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Do I have any shareholder rights?

You will not have any rights of a shareholder with respect to the SARs unless shares subject to the SARs are issued to you in settlement of the SARs. However, if the SARs are settled in cash, you will not become a shareholder, even if the amount of cash payable is determined by reference to the value of shares of common stock.

Restricted Stock

What is a restricted stock award?

    A restricted stock award is a grant of shares of PG&E Corporation common stock that is subject to vesting.

Will I be required to pay for a grant of restricted stock?

    Generally, no. It is anticipated that restricted stock awards would be granted in recognition of your service to the PG&E Corporation (or any of its subsidiaries) and would not require any cash payment. However, in setting the terms of the grant, the Committee has the discretion to require payment.

When will restricted stock awards vest?

In order for your restricted stock awards to vest, you must generally remain in the service of PG&E Corporation during the vesting period. Vesting may also be contingent upon the achievement of specified performance conditions and/or such other terms and conditions determined by the Committee. Restricted stock awards that are subject to performance-based vesting terms are referred to as Performance Shares in the LTIP, and also may be called performance share units. The vesting terms of a restricted stock award will be set forth in your award agreement.

What happens to restricted stock awards if my service with PG&E Corporation terminates before my Award vests?

    The award agreement describes what happens to the restricted stock award if your service terminates before the restricted stock award is fully vested and transferable. In general upon termination of service with the PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested restricted stock awards.

When will restricted stock awards be settled?

When restrictions on the restricted stock award lapse (i.e., you vest) and you satisfy any other conditions imposed by the Committee pursuant to the LTIP or your award agreement, you will become the owner of unrestricted shares of common stock of PG&E Corporation.

Do I have any shareholder rights?

Unless otherwise provided in your award agreement, you will have all of the rights of a shareholder with respect to restricted stock during the applicable restricted period, including the right to receive payment of dividends and distributions with respect to the underlying shares of PG&E Corporation common stock (which will be subject to the same vesting terms as the underlying shares of common stock).

Restricted Stock Units

What are restricted stock units?

A restricted stock unit is a right to receive shares of PG&E Corporation common stock when the restricted stock units are settled following vesting. PG&E Corporation common stock is not issued at the time of grant of a restricted stock unit award.

Will I be required to pay for a grant of restricted stock units?

Generally, no. It is anticipated that restricted stock unit awards would be granted in recognition of your service to the PG&E Corporation (or any of its subsidiaries) and would not require any cash payment. However, in setting the terms of the grant, the Committee has the discretion to require payment.

When will restricted stock units vest?

In order for your restricted stock awards to vest, you must generally remain in the service of PG&E Corporation during the vesting period. Vesting may also be contingent upon the achievement of

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specified performance conditions and/or such other terms and conditions determined by the Committee. Restricted stock unit awards that are subject to performance-based vesting terms are referred to as Performance Shares in the LTIP. The vesting terms of a restricted stock award will be set forth in your award agreement.

What happens to restricted stock unit awards if my service with PG&E Corporation terminates before the scheduled vesting date?

    Your award agreement describes what happens to the restricted stock unit if your service terminates before the scheduled vesting date. In general, upon termination of service with the PG&E Corporation (or any of its subsidiaries), you will forfeit all unvested restricted stock units.

Will I receive dividends on restricted stock units?

The Committee may provide in an award agreement that you will be entitled to receive dividend equivalents with respect to the payment of cash dividends, which, unless otherwise provided in an award agreement, will be credited to you in the form of additional whole restricted stock units as of the date of payment of such cash dividends on PG&E Corporation common stock. The number of additional restricted stock units (rounded to the nearest whole number) to be credited shall be determined by dividing the amount of cash dividends paid on such date with respect to the number of shares of common stock represented by the restricted stock units previously granted to you, by the fair market value of a share of common stock on such date. Settlement of dividend equivalents will be made in the same manner as the restricted stock units, which may include cash, shares of common stock of PG&E Corporation or a combination thereof.

How soon will I receive the shares after the restricted stock units have vested?     

PG&E Corporation will generally issue shares of PG&E Corporation common stock in respect of your restricted stock units within 60 days after the restricted stock units vest but no later than March 15 of the year following the year in which any applicable performance period ends or at such other times as set forth in your award agreement. However, the Committee may also settle restricted stock units in cash or a combination of cash and shares of common stock.

PG&E Corporation will delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) (relating to payments made to certain “key employees” of certain publicly-traded companies). In such event, any shares of common stock to which you would otherwise be entitled during the six-month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.

Do I have the same rights as other shareholders?

You will not have voting rights with respect to the restricted stock units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).

Performance Awards

What are performance awards?

Performance awards may be in the form of Performance Shares or Performance Units (each as may be described above) and are awards that are eligible to vest based on the achievement of performance measures at the end of a pre-established performance period (“Performance Period”), as set forth in your award agreement. Participants may receive one or more grants of performance awards, and each grant may reference one or more performance measures.

What are the performance measures and how do they work?

    A description of the applicable performance measures and how they work can be found in your award agreement.

When will performance awards vest?

Except as otherwise set forth in your ward agreement, vesting will occur following the Committee’s certification of the extent to which the performance goals applicable to each type of performance measure are achieved. Certification will occur after the completion of the relevant Performance Period.

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Termination of Service

What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if my service is terminated?

In general, and unless otherwise specified in your award agreement, upon your voluntary termination of service with PG&E Corporation (other than retirement, if provided for in your award agreement), your termination of service with or without cause, or your death or disability, you will forfeit (1) any awards that have not yet vested and (2) any associated accrued dividends. Vested options generally must be exercised within 30 days or the remaining term of the stock options, whichever is shorter.

What happens to my stock options, SARS, restricted stock, performance awards, and restricted stock units if I retire?

If applicable, your award agreement will provide for the treatment of awards in the case of retirement.

Change in Control

What happens to stock options, SARS, restricted stock, restricted stock units, and performance awards if there is a “change in control” of PG&E Corporation?

In general, and unless otherwise specified in your award agreement, in the event of a “change in control” (as defined in the LTIP), the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (“Acquiror”), may, without your consent, either assume or continue your outstanding award or the Acquiror may provide substantially equivalent awards in substitution for those awards.

In general, and unless otherwise specified in your award agreement, if the Acquiror does not assume or continue your outstanding award or if the Acquiror does not provide substantially equivalent awards, then your awards will become fully vested, and your options and SARs become exercisable immediately prior to the “change in control.”

What happens to my award if my service is terminated other than for cause in connection with a “change in control” of PG&E Corporation?

Your award agreement describes what happens to your award upon termination of your service by PG&E Corporation other than for cause in connection with a “change in control.”

What would be considered a “change in control” of PG&E Corporation?

The LTIP defines the term “change in control.” A change in control of PG&E Corporation occurs when:

•Any person becomes the beneficial owner of securities of PG&E Corporation representing 30% or more of the combined voting power of PG&E Corporation’s then outstanding securities;

•If during any two consecutive years the directors at the beginning of the two-year period cease to be a majority of the Board of Directors at the end of the period, unless the election, or the nomination for election by the shareholders, of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were either (a) directors at the beginning of the two-year period or (b) were previously elected or nominated by at least two-thirds of the directors in office at the time of the individual director’s election or nomination;

•A consolidation or merger of PG&E Corporation is consummated and results in the former PG&E Corporation shareholders owning less than 70% of the voting power in the surviving entity (or parent of the surviving entity);

•Any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of PG&E Corporation is consummated; or

•The shareholders of PG&E Corporation approve a plan of liquidation or dissolution of PG&E Corporation.

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What happens to my award if I am terminated from my position with a subsidiary of PG&E Corporation as a result of the divestiture or change in control of the subsidiary?

Your award agreement describes what happens to your award upon termination of your position by a subsidiary of PG&E Corporation as a result of a divestiture or “change in control” of the subsidiary.

Transferability: Resale Restrictions

May I transfer my stock options, SARS, restricted stock, restricted stock units, and performance awards to someone else?

Unless otherwise specified in your award agreement in accordance with the terms of the LTIP, you may not transfer your stock options, SARS, restricted stock, performance awards, or restricted stock units during your lifetime other than pursuant to a qualified domestic relations order (QDRO) or similar court order.After your death, your awards may be transferred in accordance withyour will or in accordance with the laws of descent and distribution. Except for options that may have been transferred as described above, your options may be exercised during your lifetime only by you, your duly appointed legal representative, or the person named in a QDRO.

Are there any restrictions on my ability to sell common stock received when my awards are settled in shares of common stock or when I exercise my stock options?

You are free to sell your stock at any time, except when you are subject to a trading blackout or while you are in possession of nonpublic material information about PG&E Corporation or any of its subsidiaries. Confidential, nonpublic information should be considered material if there is substantial likelihood that a reasonable investor would consider the information important. You are prohibited by securities laws and by PG&E Corporation’s and Pacific Gas and Electric Company’s Insider Trading Policy from trading in securities of PG&E Corporation or Pacific Gas and Electric Company until the information has been disclosed and widely disseminated to the investing public, typically two full trading days following such disclosure. Also, if as determined by PG&E Corporation, your position exposes you to nonpublic material information, you may be temporarily prohibited from trading shares. You will be notified if this “blackout” period applies to you.

What if I am an executive officer of PG&E Corporation?

If you are an executive officer of PG&E Corporation or Pacific Gas and Electric Company, you will be prohibited from engaging in transactions involving securities of PG&E Corporation or Pacific Gas and Electric Company during quarterly blackout periods and you will be subject to the other conditions of PG&E Corporation’s and Pacific Gas and Electric Company’s Insider Trading Policy (in particular, requiring 10b5-1 plans for your transactions in PG&E shares subject to this prospectus). Executive officers of PG&E Corporation will be considered “affiliates” of PG&E Corporation (along with their spouses and other relatives sharing the same household). In general, if you are an affiliate of PG&E Corporation, your sales of shares must comply with SEC Rule 144. In addition, executive officers of PG&E Corporation and Pacific Gas and Electric Company are subject to the reporting and short-swing profit liability provisions of Section 16 of the Securities Exchange Act of 1934 Act with respect to their transactions in PG&E Corporation common stock and Pacific Gas and Electric Company preferred securities, respectively. Information regarding Rule 144 and Section 16 is available from the Corporate Secretary.

In addition, you will not be able to buy or sell your shares if you are subject to the trading restrictions imposed by the Sarbanes Oxley Act of 2002 in connection with a blackout period under a PG&E Corporation sponsored retirement plan.

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Tax Consequences

    The following is a general description of the United States federal income tax consequences relating to your awards under the Code as currently in effect and is not intended to be a complete description of all the possible tax consequences. Federal tax treatment may change should the Code be amended. The consequences may differ based on your personal situation. PG&E Corporation cannot assure you of any particular tax result and is not providing you with tax advice. If you have any questions regarding the tax consequences of receiving a grant of stock options, SARS, restricted stock, restricted stock units, and performance awards you should contact your tax advisor. PG&E Corporation makes no representation that the LTIP will comply with Section 409A and makes no undertaking to prevent Section 409A from applying to the LTIP or any award or to mitigate its effects on any award.

You will be required to pay to PG&E Corporation, or to make arrangements satisfactory to PG&E Corporation for the payment of withholding taxes, including social security and Medicare taxes due under the Federal Insurance Contributions Act (FICA), and the California State Disability Insurance (SDI) tax that become due in connection with your awards. PG&E Corporation’s obligations under the LTIP and your award agreement are subject to payment of, or to the arrangement for payment of, all withholding taxes. PG&E Corporation will have the right, to the extent permitted by law, to deduct any such withholding taxes from any payment of any kind otherwise due to you.

Are there any tax consequences when I am granted a nonqualified stock option or SARs?

In general, there are no immediate federal income tax consequences when you are granted nonqualified stock options or SARs.

What are the tax consequences when I exercise my stock options or SARs?

When you exercise a nonqualified stock option or SAR, you generally will have taxable ordinary income equal to the difference between the current fair market value of the shares of common stock and the exercise price or base price. The amount of ordinary income will be included in your W-2 form for the year in which you exercised your stock option or SAR.

Will my exercise of a stock option or SAR be subject to tax withholding?

Yes. In connection with the exercise of a nonqualified stock option or SAR, PG&E Corporation will be required to withhold applicable taxes on income you recognize upon the exercise. Please see your award agreement for the methods by which you may satisfy the applicable withholding taxes.

What are the tax consequences if I sell the shares purchased upon exercise of a stock option?

If you sell the shares you purchased upon exercise of your nonqualified stock options you will be taxed on the excess of the sale price over the market value of the shares on the exercise date (your tax basis). (The market value of the shares on the date of exercise will be the sum of the option exercise price plus the amount of ordinary income you recognized when the option was exercised.) Whether or not this amount can be treated as long-term capital gain (or loss) depends on the length of time you held the shares before selling them. Currently, to receive long-term capital gain treatment you must hold the stock for more than one year. If you are subject to alternative minimum tax, you should consult your tax advisor.

If you paid the option exercise price by delivering shares you already owned, then the tax consequences upon sale of the shares are slightly different. Your tax basis in the surrendered shares and the length of time (the holding period) that you held the surrendered shares will be carried over to an equal number of shares that you acquired upon exercise. If you purchased more shares than the number of shares you delivered, the holding period for the excess shares will start on the date of exercise and the price of such shares will be equal to the market value of the shares on the date of exercise.

Are there any tax consequences when I am granted an incentive stock option?

In general, there are no immediate federal income tax consequences when you are granted incentive stock options.

What are the tax consequences when I exercise my incentive stock options?

You will not recognize any taxable income, for regular income tax purposes, at the time an incentive stock option is exercised. However, the amount by which the fair market value (at the time of exercise) of the purchased shares exceeds the exercise price paid for those shares will constitute an adjustment to your income for purposes of the alternative minimum tax.

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What are the tax consequences if I sell the shares purchased upon exercise of an incentive stock option?

    The federal income tax liability will depend upon whether you make a qualifying or disqualifying disposition of the shares purchased under the incentive stock option. Subject to certain requirements in the Code, a qualifying disposition will occur if the sale or other disposition of shares takes place more than two years after the date the incentive stock option was granted and more than one year after the date that the stock option was exercised for the particular shares involved in the disposition. A disqualifying disposition is any sale or other disposition made before both of these requirements are satisfied.

What if I make a qualifying disposition?

    You will recognize a long-term capital gain equal to the excess of (a) the amount realized upon the sale or other disposition over (b) the exercise price paid for the shares. You will recognize a long-term capital loss if the amount realized is lower than the exercise price paid for the shares.

What if I make a disqualifying disposition?

    If you dispose of shares before the minimum holding periods described above have been satisfied, you will recognize ordinary income at the time of the disposition in an amount equal to the fair market value of the shares on the exercise date over the exercise price paid for those shares. Any additional gain recognized on the disqualifying disposition will be taxable at capital gains rates (long-term if the shares have been held for more than one year following the exercise date of the option). If the sale proceeds from a disqualifying disposition are less than the fair market value of the shares on the date of exercise, any ordinary income recognized is limited to the gain (if any) realized on the sale.

What are the tax consequences relating to restricted stock (including any Performance Share awards)?

    You will not recognize income until the transfer restrictions and forfeiture provisions lapse (i.e., you vest) unless you voluntarily elect to recognize income on the date of grant by filing an election under Section 83(b) of the Code. If you do not make a Section 83(b) election, then at the time that the transfer restrictions and forfeiture provisions lapse, you will recognize as ordinary income an amount equal to the excess of the fair market value of the shares on the date of lapse over the purchase price (if any) paid for such shares.

What is a Section 83(b) election?

    A Section 83(b) election is available only for awards of restricted stock (including performance shares). Section 83(b) allows you to recognize ordinary income on the fair market value of the restricted stock on the date of grant instead of on the date the award vests. Thereafter, any further gain or loss recognized upon the ultimate sale or disposition of the restricted stock is treated as capital gain or loss. Section 83(b) elections may be made with respect to restricted stock awards, to the extent permitted by the Committee.

How are dividends and dividend equivalents related to my restricted stock awards taxed?

Any dividends received with respect to a restricted stock award will be subject to the same vesting terms as the related restricted stock award. If you do not make a Section 83(b) election, you will not recognize ordinary income with respect to the dividends until the related restricted stock award vests (and therefore the dividends vest).

What are the tax consequences relating to restricted stock units (including Performance Units)?

You will not recognize income until the restricted stock units are settled. Generally, when your restricted stock units are settled after vesting, you will have taxable ordinary income in the amount of the fair market value of the shares received in connection with the settlement of the restricted stock units and you will be required to satisfy applicable withholding taxes.

In the following situations you may be required to satisfy FICA and California SDI taxes even though the restricted stock units have not yet been settled:

•If you are retirement-eligible on the date of the award (if your award agreement provides for continued vesting after retirement),

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•When you become “retirement-eligible,” if your award agreement provides for continued vesting after retirement,

•If your service is terminated other than for cause (as described in your award agreement), or

•Any other situations under which your restricted stock units vest before they are settled.

How can I satisfy the amount of California SDI and FICA taxes that may be due before my restricted stock units are settled?

Under these circumstances FICA and California SDI taxes must be paid either by check payable to PG&E Corporation or through payroll deductions. Unless you deliver a check to PG&E Corporation, the amount will be satisfied through payroll deductions.

How can I satisfy the withholding taxes that arise when my restricted stock units vest?

    You must arrange to pay the withholding taxes that arise when your restricted stock units vest in a manner acceptable to PG&E Corporation. PG&E Corporation may withhold from the shares otherwise issuable to you in settlement of restricted stock units a number of whole shares having a fair market value, as determined by PG&E Corporation, equal to the applicable withholding taxes. The remaining number of whole shares will be issued to you.

What are the tax consequences if I sell shares I acquire upon vesting of restricted stock unit awards or settlement of my restricted stock units?    

If you recognize gain when you sell shares your gain will be taxable at long-term or short-term capital gain rates. If you recognize a loss, it will be a capital loss. The amount of your gain or loss will be the difference between the amount you receive on the sale of the shares and the value used to calculate the applicable withholding taxes when your award was settled. Whether your gain or loss is long-term or short-term will depend on whether you have held your shares for more than one year. The holding period generally begins at the time your performance awards or restricted stock units are settled or stock options are exercised, and shares are issued to you.

What is the impact of Section 409A of the Code on my awards?

    If an award is treated as “nonqualified deferred compensation” and the award does not comply with or is not exempt from Section 409A, Section 409A may impose additional taxes, interest and penalties on you. All grants made under the LTIP are designed and intended to either be exempt from or comply with Section 409A to avoid such additional taxes, interest and penalties. Neither the Committee nor PG&E Corporation is obligated to ensure that awards comply with Section 409A or to take any actions to ensure such compliance.

Additional Information about PG&E Corporation

PG&E Corporation has filed a registration statement relating to the offer and sale of its shares of common stock under the LTIP with the Securities and Exchange Commission (SEC). The following documents filed by PG&E Corporation with the SEC are incorporated by reference into the registration statement and into this prospectus:

•The annual report on Form 10-K of PG&E Corporation;

•Quarterly reports on Form 10-Q and Current Reports on Form 8-K;

•All other documents filed with the SEC pursuant to Section 13(a), 13(c), 14 and 15(a) of the Securities Exchange Act of 1934, as amended; and

•The description of PG&E Corporation common stock filed with the SEC, including any amendment or report filed for the purpose of updating such description.

All documents filed with the SEC by PG&E Corporation after the date the registration statement was filed and before the filing of a post-effective amendment to the registration statement that indicates all securities offered under the LTIP have been sold or deregisters all securities then remaining unsold, will also be incorporated by reference in this summary and deemed to be a part of this summary as of the date such documents are filed with the SEC.

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Copies of the documents listed above (other than exhibits to such documents), and copies of PG&E Corporation’s latest annual report to shareholders, proxy statement, reports, and other communications sent to shareholders, will be sent to you without charge upon your request. Requests may be directed to:

Office of the Corporate Secretary

PG&E Corporation

77 Beale Street    P.O. Box 770000

San Francisco, California 94177

(Telephone: 415-973-8200)

These reports are also available through PG&E Corporation’s website at www.pgecorp.com, through the SEC’s website at www.sec.gov, and through various financial websites.

PG&E Corporation’s filings with the SEC, including its Annual Report on Form 10-K are available on PG&E Corporation’s website at www.pgecorp.com under the “Investors” link. (Click on “Financial Reports” and then click on “SEC Filings.”)

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EX-10.99

EXHIBIT 10.99

PG&E CORPORATION
2012 OFFICER SEVERANCE POLICY
(Amended effective as of November 1, 2021)

1.Purpose. This is the controlling and definitive statement of the Officer Severance Policy of PG&E Corporation (“Policy”). Since Officers (defined below) are employed at the will of PG&E Corporation (“Corporation”) or a participating employer (“Employer”), their employment may be terminated at any time, with or without cause. A list of Employers is attached hereto as Appendix A. The Policy became effective March 1, 2012, and provides employees with the positions of Vice President, Senior Vice President, Executive Vice President or higher at the time of termination (“Officers”) of the Corporation and Employers with severance benefits if their employment is terminated.1 The Policy’s definition of Change in Control was amended effective May 12, 2014.2 The Policy’s treatment of STIP payouts and limitations on certain severance payments were added effective September 25, 2020. The value of and eligibility for severance benefits was amended effective November 1, 2021. For the avoidance of doubt, revisions made to this Policy relating to Code Section 409A (defined below), apply to all Officers including those that may be covered under prior provisions of the Policy as required by Section 6 hereof.

The purpose of the Policy is to attract and retain Officers by defining terms and conditions for severance benefits, to provide severance benefits that are part of a competitive total compensation package, to provide consistent treatment for all terminated officers, and to minimize potential litigation costs associated with Officer termination of employment.

2.Termination of Employment Not in Connection with Change in Control .

(a)Corporation or Employer’s Obligations. If the Corporation or an Employer exercises its right to terminate an Officer’s employment without cause and such termination does not entitle Officer to payments under Section 3, the Officer shall be given thirty (30) days’ advance written notice or pay in lieu thereof (which shall be paid in a lump sum together with the payment described in Section 2(a)(1) below). Except as provided in Section 2(c) below, in consideration of the Officer’s agreement to the obligations described in Section 4 below and to the arbitration provisions described in Section 13 below, the following payments and benefits shall also be provided to Officer following Officer’s separation from service (within the meaning of Code Section 409A):3

(1)A lump sum severance payment equal to the sum of the Officer’s annual base compensation and the Officer’s Short-Term Incentive Plan (“STIP”) target award at the time of his or her termination) (the “Severance Base Amount”); provided, however, that for purposes of this section 2(a)(1), any lump sum severance payment for the Corporation’s Chief

1.    Severance benefits for Officers who are currently covered by an employment agreement will continue to be provided solely under such agreements until their expiration at which time this Policy will become effective for such Officers. Specific elements of any officer’s severance benefits may be amended by appropriate Board-level approval. Any Officer’s waiver of benefits under this Policy shall take precedence over the terms of this Policy. If an employee becomes a covered Officer under this Policy as a result of a promotion, and if such Officer was then covered by a severance arrangement subject to Section 409A of the Internal Revenue Code of 1986 (“Code Section 409A”), the severance benefits under this Policy provided to such person shall comply with the time and form of payment provisions of such prior severance arrangement, to the extent required by Code Section 409A.

    .

2Any payments made hereunder shall be less applicable taxes.

Executive Officer shall be equal to the product of (1) two and (2) such officer’s Severance Base Amount. Annual base compensation shall mean the Officer’s monthly base pay for the month in which the Officer is given notice of termination, multiplied by 12. The payment described in this Section 2(a)(1) shall be made in a single lump sum as soon as practicable following the date the release of claims described in Section 2(e)(1) becomes effective, provided that payment shall in no event be made later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs;

(2)Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, the equity-based incentive awards granted to Officer under the Corporation’s Long-Term Incentive Program (“LTIP”) which have not yet vested as of the date of termination will continue to vest over a period of twelve months after the date of termination as if the Officer had remained employed for such period. Except as otherwise set forth in the applicable award agreement, for vested stock options as of the date of termination, the Officer shall have the right to exercise such stock options at any time within their respective terms or within five years after termination, whichever is shorter. Except as otherwise set forth in the applicable award agreement, for stock options that vest during a period of twelve months, the Officer shall have the right to exercise such options at any time within one year after termination, subject to the term of the options. Except as otherwise set forth in the applicable award agreement, any unvested equity-based incentive awards remaining at the end of such period shall be forfeited;

(3) A prorated annual incentive payment equal to the annual incentive payment, if any, that the Officer would have earned for the entire calendar year in which the termination occurs pursuant to the Officer’s then-current STIP; based on Eligible Earnings paid between January 1 of such calendar year and the Officer’s date of termination (a “Pro-Rata Incentive”). Subject to Section 14, an Officer’s Pro-Rata Incentive shall be paid by the Officer’s former employer on the date that annual incentive payments are paid to the Employers’ active employees. Notwithstanding the foregoing, the People and Compensation Committee (or its successor) of the Corporation may, decrease, or eliminate the Pro-Rata Incentive for the Officer in its sole discretion. For purposes of this section, “Eligible Earnings” means the sum of the Officer’s: base pay, including paid time off; lump-sum payments as part of a merit increase; temporary assignment pay, including lump-sum payments; and for an Officer on Paid Family Leave or Short-Term Disability, payments made for approved leaves;

(4)    A lump sum cash payment equal to the estimated value of 18 months’of COBRA premiums for the Officer, based on the Officer’s benefit levels at the time of termination (with such payment subject to taxation under applicable law);

(5)    To the extent not theretofore paid or provided, the Officer shall be paid or provided with any other amounts or benefits required to be paid or provided or which the Officer is eligible to receive under any plan, contract or agreement of the Corporation or Employer;

(6)    A lump sum cash payment of $19,500, equal to the estimated reasonable value of career transition services for the Officer following separation from service.

(7)    All acts required of the Employer under the Policy may be performed by the Corporation for itself and the Employer, and the costs of the Policy may be equitably apportioned by the Administrator among the Corporation and the other Employers. The Corporation shall be responsible for making payments and providing benefits pursuant to this Policy for Officers employed by the Corporation. Whenever the Employer is permitted or required under the terms of the Policy to do or perform any act, matter or thing, it shall be done and performed by any Officer or employee of the Employer who is thereunto duly authorized by

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the board of directors of the Employer. Each Employer shall be responsible for making payments and providing benefits pursuant to the Policy on behalf of its Officers or for reimbursing the Corporation for the cost of such payments or benefits, as determined by the Corporation in its sole discretion. In the event the respective Employer fails to make such payment or reimbursement, an Officer’s (or other payee’s) sole recourse shall be against the respective Employer, and not against the Corporation;

(b)Remedies. An Officer shall be entitled to recover damages for late or nonpayment of amounts to which the Officer is entitled hereunder. The Officer shall also be entitled to seek specific performance of the obligations and any other applicable equitable or injunctive relief.

(c)Section 2(a) shall not apply in the event that an Officer’s employment is terminated “for cause.” Except as used in Section 3 of this Policy, “for cause” means that the Corporation, in the case of an Officer employed by the Corporation, or Employer in the case of an Officer employed by an Employer, acting in good faith based upon information then known to it, determines that the Officer has engaged in, committed, or is responsible for (1) serious misconduct, gross negligence, theft, or fraud against the Corporation and/or an Employer; (2) refusal or unwillingness to perform his duties; (3) inappropriate conduct in violation of Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationship of the Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty; or (9) any breach of the restrictive covenants contained in Section 4 below. Upon termination “for cause,” the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries shall have no liability to the Officer other than for accrued salary, vacation benefits, and any vested rights the Officer may have under the benefit and compensation plans in which the Officer participates and under the general terms and conditions of the applicable plan.

(d)The Board of Directors of the Corporation and the Board of Directors of Pacific Gas and Electric Company (the “Utility”) reserve the right to: (a) restrict, limit, cancel, reduce or require forfeiture of payments or benefits pursuant to the provisions of Section 2(a), (i) for any executive officer of the Utility (as defined in California Public Utilities Code § 451.5) or any executive officer of the Corporation (as defined in Rule 3b-7 under the Securities Exchange Act of 1934) in the event of any felony conviction of the Corporation or the Utility related to public health and safety or financial misconduct by the Corporation or the Utility following its July 1, 2020 emergence from Chapter 11 bankruptcy, provided that such executive officer was serving as an executive officer of the Corporation or the Utility, as applicable, at the time of the underlying conduct that led to the conviction (“Company Conviction”), or (ii) for the chief executive officer or chief financial officer of the Corporation or the Utility if that entity is required to prepare a restatement of the financial statement due to the material noncompliance of the Corporation or the Utility, as applicable, with any financial reporting requirement under the federal securities laws, as a result of misconduct, provided that only the payment and benefits under Section 2(a) that the chief executive officer or chief financial officer is eligible to receive during the twelve (12)-month period following the first public issuance or filing with the Securities and Exchange Commission (whichever first occurs) of the financial statement are subject to restriction, limitation, cancellation, reduction or forfeiture and further provided the executive officer was serving as a chief executive officer or chief financial officer of the Corporation or the Utility, as applicable, during the period for which the financial statement is restated; and (b) recoup or require reimbursement or repayment of rights, payments, and benefits under Section 2(a) for any executive officer of the Utility (as defined in California Public Utilities Code § 451.5) or any executive officer of the Corporation (as defined in Rule 3b-7 under

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the Securities Exchange Act of 1934) in the event such executive officer engaged in misconduct that materially contributed to some of the actions or omissions on which the Company Conviction is based (as determined by the applicable Board in its discretion). The Corporation, the Utility, their affiliates, and their respective directors, officers, and employees shall have no liability to any such executive officer, including the chief executive officer and chief financial officer of the Corporation or the Utility, in the event of restriction, limitation, reduction, recoupment, forfeiture, reimbursement, or cancellation of the provisions of Section 2(a), other than for accrued salary, vacation benefits, and any vested rights such executive officer may have under the benefit and compensation plans in which the executive officer participates and under the general terms and conditions of the applicable plan.

3.Termination of Employment In Connection With a Change in .

(a)If an Executive Officer’s (defined below) employment by the Corporation or any subsidiary or successor of the Corporation shall be subject to an Involuntary Termination within the Covered Period, then the provisions of this Section 3 instead of Section 2 shall govern the obligations of the Corporation as to the payments and benefits it shall provide to the Executive Officer. In the event that Executive Officer’s employment with the Corporation or an employing subsidiary is terminated under circumstances which would not entitle Executive Officer to payments under this Section 3, Executive Officer shall only receive such benefits to which he is entitled under Section 2, if any. In no event shall Executive Officer be entitled to receive termination benefits under both this Section 3 and Section 2.

All the terms used in this Section 3 shall have the following meanings:

(1)“Affiliate” shall mean any entity which owns or controls, is owned or is under common ownership or control with, the Corporation.

(2)“Cause” shall mean (i) the willful and continued failure of the Executive Officer to perform substantially the Executive Officer’s duties with the Corporation or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive Officer by the Board of Directors or the Chief Executive Officer of the Corporation which specifically identifies the manner in which the Board of Directors or Chief Executive Officer believes that the Executive Officer has not substantially performed the Executive Officer’s duties; or (ii) the willful engaging by the Executive Officer in illegal conduct or gross misconduct which is materially demonstrably injurious to the Corporation.

For purposes of the provision, no act or failure to act, on the part of the Executive Officer, shall be considered “willful” unless it is done, or omitted to be done, by the Executive Officer in bad faith or without reasonable belief that the Executive Officer’s action or omission was in the best interests of the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer or a senior officer of the Corporation or based upon the advice of counsel for the Corporation shall be conclusively presumed to be done, or omitted to be done, by the Executive Officer in good faith and in the best interests of the Corporation. The cessation of employment of the Executive Officer shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive Officer a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of Directors at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Executive Officer and the Executive Officer is given an opportunity, together with counsel, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Executive Officer is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.

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(3)“Change in Control” shall mean the occurrence of any of the following:

a.any “person” (as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 (“Exchange Act”), but excluding any benefit plan for employees or any trustee, agent or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Exchange Act) of securities of the Corporation representing thirty percent (30%) or more of the combined voting power of the Corporation’s then outstanding voting securities; or

b.during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors of the Corporation (“Board”) cease for any reason to constitute at least a majority of the Board, unless the election, or the nomination for election by the shareholders of the Corporation, of each new member of the Board (“Director”) was approved by a vote of at least two-thirds (2/3) of the Directors then still in office (1) who were Directors at the beginning of the period or (2) whose election or nomination was previously so approved; or

c.the consummation of any consolidation or merger of the Corporation other than a merger or consolidation which would result in the holders of the voting securities of the Corporation outstanding immediately prior thereto continuing to directly or indirectly hold at least seventy percent (70%) of the Combined Voting Power of the Corporation, the surviving entity in the merger or consolidation or the parent of such surviving entity outstanding immediately after the merger or consolidation; or

d.(1) the consummation of any sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Corporation or (2) the approval of the shareholders of the Corporation of a plan of liquidation or dissolution of the Corporation.

(4)“Change in Control Date” shall mean the date on which a Change in Control occurs.

(5)“Combined Voting Power” shall mean the combined voting power of the Corporation’s or other relevant entity’s then outstanding voting securities.

(6)“Covered Period” shall mean the period commencing three months prior to the Change in Control Date and terminating two (2) years following said Change in Control Date.4

(7)“Disability” shall mean the absence of the Executive Officer from the Executive Officer’s duties with the Corporation or the employing subsidiary on a full-time basis for 180 consecutive business days as a result of incapacity due to physical or mental illness which is determined to be total and permanent by a physician selected by the Corporation or its insurers and acceptable to the Executive Officer or the Executive Officer’s legal representative.

(8)“Executive Officer” shall mean officers of the Corporation or an Employer with titles of Senior Vice President, Executive Vice President, or higher at time of Involuntary Termination.

4For a period of three years following notification of this definition of “Covered Period,” Executive Officers who were eligible for benefits under Section 3 as of November 1, 2021, will continue to be subject to the defintion of “Covered Period” as set forth in the Policy as effective September 24, 2020.

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(9)“Good Reason” shall mean any one or more of the following which takes place within the Covered Period:

a.    A material diminution in the Executive Officer’s base compensation;

            b.    A material diminution in the Executive Officer’s authority, duties, or responsibilities;

            c.    A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive Officer is required to report, including a requirement that the Executive Officer report to a corporate officer or employee instead of reporting directly to the Board of Directors of the Corporation (in the case of an Executive Officer reporting to such Board of Directors);

            d.    A material diminution in the budget over which the Executive Officer retains authority;

            e.    A material change in the geographic location at which the Executive Officer must perform the services; or

            f.    Any other action or inaction that constitutes a material breach by the Corporation of this Policy;

provided, however, that the Executive Officer must provide notice to the Corporation of the existence of the applicable condition described in this Section 3(a)(9) within 90 days of the initial existence of the condition, upon the notice of which the Corporation shall have 30 days during which it may remedy the condition and, if remedied, Good Reason shall not exist.

(10) “Involuntary Termination” shall mean a termination (i) by the Corporation without Cause, or (ii) by Executive Officer following Good Reason; provided, however, the term "Involuntary Termination" shall not include termination of Executive Officer’s employment due to Executive Officer’s death, Disability, or voluntary retirement.

(11)“Reference Salary” shall mean the greater of (i) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the date of Executive Officer’s Involuntary Termination, or (ii) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the Change in Control Date.

(12)“Termination Date” shall be the date specified in the written notice of termination of Executive Officer’s employment given by either party in accordance with Section 3(b) of this Policy.

(b)Notice of Termination. During the Covered Period, in the event that the Corporation (including an employing subsidiary) or Executive Officer terminates Executive Officer’s employment with the Corporation or Employer, the party terminating employment shall give written notice of termination to the other party, specifying the Termination Date and the specific termination provision in this Section 3 that is relied upon, if any, and setting forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive Officer’s employment under the provision so indicated. The Termination Date shall be determined as follows: (i) if Executive Officer’s employment is terminated for Disability, thirty (30) days after a Notice of Termination is given (provided that Executive Officer shall not have returned to the full-time performance of Executive Officer’s duties during such 30-day

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period); (ii) if Executive Officer’s employment is terminated by the Corporation in an Involuntary Termination, thirty days after the date the Notice of Termination is received by Executive Officer (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below); and (iii) if Executive Officer’s employment is terminated by the Corporation for Cause (as defined in this Section 3), the date specified in the Notice of Termination, provided, that the events or circumstances cited by the Board of Directors as constituting Cause are not cured by Executive Officer during any cure period that may be offered by the Board of Directors. The Date of Termination for a resignation of employment other than for Good Reason shall be the date set forth in the applicable notice, which shall be no earlier than ten (10) days after the date such notice is received by the Corporation, unless waived by the Corporation.

During the Covered Period, a otice of termination given by Executive Officer for Good Reason shall be given within 90 days after occurrence of the event on which Executive Officer bases his notice of termination and shall provide a Termination Date of thirty (30) days after the notice of termination is given to the Corporation (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below).

(c)Corporation’s Obligations. If Executive Officer separates from service due noExecutive Officer the following benefits:

(1)The Corporation shall pay to the Executive Officer a lump sum in cash within thirty (30) days after the later of the Change in Control Date or the Executive Officer’s separation from service:

a.the sum of (1) any earned but unpaid base salary through the Termination Date at the rate in effect at the time of the notice of termination to the extent not theretofore paid; (2) the Executive Officer’s target bonus under the STIP of the Corporation, an Affiliate, or a predecessor, for the fiscal year in which the Termination Date occurs (the “Target Bonus”), pro-rated to reflect service during that year; and (3) any accrued but unpaid vacation pay, in each case to the extent not theretofore paid;

b.the amount equal to the product of (1) two and (2) the sum of (x) the Reference Salary and (y) the Target Bonus; provided, however, that for the Corporation’s Chief Executive Officer, such amount shall be equal to the product of (1) three and (2) the sum of (x) the Reference Salary and (y) the Target Bonus;

c.a lump sum cash payment equal to the estimated value of 18 months’of COBRA premiums for the Executive Officer, based on the Executive Officer’s benefit levels at the time of termination (with such payment subject to taxation under applicable law), if any; and

d.    a lump sum cash payment of $19,500, equal to the estimated reasonable value of career transition services for the Officer following separation from service.

(2)Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, in the event of involuntary termination in connection with a Change in Control in which equity-based awards granted to the Executive Officer under the LTIP are not assumed or continued, Executive Officer’s then-outstanding awards that are not vested shall immediately vest in full, and all performance conditions associated with performance-based LTIP awards shall be deemed satisfied as if target performance was achieved, and shall be settled in cash, shares or a combination thereof, as determined by the People and Compensation Committee (or its successor), within thirty (30) days following such Change in

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Control (except to the extent that settlement of the award must be made pursuant to its original schedule in order to comply with Code Section 409A), notwithstanding that the applicable performance period, retention period or other restrictions and conditions have not been completed or satisfied.

(3)Remedies. The Executive Officer shall be entitled to recover damages for late or nonpayment of amounts which the Corporation is obligated to pay hereunder. The Executive Officer shall also be entitled to seek specific performance of the Corporation’s obligations and any other applicable equitable or injunctive relief.

(d)Adjustment for Excise Taxes.

(1) “Best-Net Provision”

Subject to Section 3(d)(2) below, in the event that the payments and other benefits provided for in this Policy or otherwise payable to Executive Officer (i) constitute “parachute payments” within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”) and (ii) would be subject to the excise tax imposed by Section 4999 of the Code, then Executive Officer’s payments and benefits under this Policy or otherwise payable to Executive Officer outside of this Policy shall be either delivered in full (without the Corporation paying any portion of such excise tax), or delivered as to 2.99 times of Executive's base amount (within the meaning of Section 280G of the Code) so as to result in no portion of such payments and benefits being subject to such excise tax, whichever of the foregoing amounts, taking into account the applicable federal, state and local income taxes and such excise tax, results in the receipt by Executive Officer on an after-tax basis of the greatest amount of payments and benefits, notwithstanding that all or some portion of such payments and benefits may subject to such excise tax. Unless the Corporation and Executive Officer otherwise agree in writing, any determination required under this Section 3(d)(1) shall be made in writing by Deloitte & Touche (the “Accounting Firm”), whose determination shall be conclusive and binding upon Executive Officer and the Corporation for all purposes. For purposes of making the calculations required by this Section 3(d)(1), the Accounting Firm may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of Section 280G and 4999 of the Code. The Corporation and Executive Officer shall furnish to the Accounting Firm such information and documents as the Accounting Firm may reasonably request in order to make a determination under this Section 3(d)(1).

Any reduction in payments and/or benefits shall occur in the following order as reasonably determined by the Accounting Firm: (1) reduction of cash payments, (2) reduction of non-cash/non-equity-based payments or benefits, and (3) reduction of vesting acceleration of equity-based awards; provided, however, that any non-taxable payments or benefits shall be reduced last in accordance with the same categorical ordering rule.  In the event items described in (1) or (2) are to be reduced, reduction shall occur in reverse chronological order such that the payment or benefit owed on the latest date following the occurrence of the event triggering the excise tax will be the first payment to be reduced (with reductions made pro-rata in the event payments are owed at the same time).  In the event that acceleration of vesting of equity-based awards is to be reduced, such acceleration of vesting shall be cancelled in a manner such as to obtain the best economic benefit for the officer (with reductions made pro-rata if economically equivalent), as determined by the Accounting Firm.

4.Obligations of Officer.

(1)Release of Claims. There shall be no obligation to commence the payment of the amounts and benefits described in Section 2(a) or Section 3(c) (as applicable) until the latter of (1) the delivery by Officer to the Corporation a fully executed comprehensive general release of

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any and all known or unknown claims that he or she may have against the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries and a covenant not to sue in the form prescribed by the Administrator, and (2) the expiration of any revocation period set forth in the release. The Corporation shall promptly furnish such release to Officer in connection with the Officer’s separation from service, and such release must be executed by Officer and become effective during the period set forth in the release as a condition to Officer receiving the payments and benefits described in Section 2(a) or Section 3(c) (as applicable).

(2)Covenant Not to Compete. (i) During the period of Officer’s employment with the Corporation or its subsidiaries and for a period of twelve (12) months thereafter (the “Restricted Period”), Officer shall not, in any county within the State of California or in any city, county or area outside the State of California within the United States or in the countries of Canada or Mexico, directly or indirectly, whether as partner, employee, consultant, creditor, shareholder, or other similar capacity, promote, participate, or engage in any activity or other business competitive with the Corporation’s business or that of any of its subsidiaries or affiliates, without the prior written consent of the Corporation’s Chief Executive Officer. Notwithstanding the foregoing, Officer may have an interest in any public company engaged in a competitive business so long as Officer does not own more than 2 percent of any class of securities of such company, Officer is not employed by and does not consult with, or becomes a director of, or otherwise engage in any activities for, such competing company.

(1)The Corporation and its subsidiaries presently conduct their businesses within each county in the State of California and in areas outside California that are located within the United States, and it is anticipated that the Corporation and its subsidiaries will also be conducting business within the countries of Canada and Mexico. Such covenants are necessary and reasonable in order to protect the Corporation and its subsidiaries in the conduct of their businesses. To the extent that the foregoing covenant or any provision of this Section4(b)(1) shall be deemed illegal or unenforceable by a court or other tribunal of competent jurisdiction with respect to (i) any geographic area, (ii) any part of the time period covered by such covenant, (iii) any activity or capacity covered by such covenant, or (iv) any other term or provision of such covenant, such determination shall not affect such covenant with respect to any other geographic area, time period, activity or other term or provision covered by or included in such covenant.

(3)Soliciting Customers and Employees. During the Restricted Period, Officer shall not, directly or indirectly, solicit or contact any customer or any prospective customer of the Corporation or its subsidiaries or affiliates for any commercial pursuit that could be reasonably construed to be in competition with the Corporation, or induce, or attempt to induce, any employees, agents or consultants of or to the Corporation or any of its subsidiaries or affiliates to do anything from which Officer is restricted by reason of this covenant nor shall Officer, directly or indirectly, offer or aid to others to offer employment to, or interfere or attempt to interfere with any employment, consulting or agency relationship with, any employees, agents or consultants of the Corporation, its subsidiaries and affiliates, who received compensation of $75,000 or more during the preceding six (6) months, to work for any business competitive with any business of the Corporation, its subsidiaries or affiliates.

(4)Confidentiality. Officer shall not at any time (including after termination of employment) divulge to others, use to the detriment of the Corporation or its subsidiaries or affiliates, or use in any business competitive with any business of the Corporation or its subsidiaries or affiliates any trade secret, confidential or privileged information obtained during his employment with the Corporation or its subsidiaries or affiliates, without first obtaining the written consent of the Corporation’s Chief Executive Officer. This paragraph covers but is not limited to discoveries, inventions (except as otherwise provided by California law), improvements, and writings, belonging to or relating to the affairs of the Corporation or of any of

9

its subsidiaries or affiliates, or any marketing systems, customer lists or other marketing data. Officer shall, upon termination of employment for any reason, deliver to the Corporation all data, records and communications, and all drawings, models, prototypes or similar visual or conceptual presentations of any type, and all copies or duplicates thereof, relating to all matters contemplated by this paragraph.

(5)Assistance in Legal Proceedings. During the Restricted Period, Officer shall, upon reasonable notice from the Corporation, furnish information and proper assistance (including testimony and document production) to the Corporation as may be reasonably required by the Corporation in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of the Corporation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Corporation shall pay all reasonable expenses incurred by Officer in complying with this paragraph within 60 days after Officer incurs such expenses.

(6)Remedies. Upon Officer’s failure to comply with the provisions of this Section 4, the Corporation shall have the right to immediately terminate any unpaid amounts or benefits described in Section 2(a) or Section 3 (as applicable) to Officer. In the event of such termination, the Corporation shall have no further obligations under this Policy and shall be entitled to recover damages. In the event of an Officer’s breach or threatened breach of any of the covenants set forth in this Section 4, the Corporation shall also be entitled to specific performance by Officer of any such covenant and any other applicable equitable or injunctive relief.

5.Administration. The Policy shall be administered by the Senior Human Resources Officer of the Corporation (“Administrator”), who shall have the authority to interpret the Policy and make and revise such rules as may be reasonably necessary to administer the Policy. The Administrator shall have the duty and responsibility of maintaining records, making the requisite calculations, securing Officer releases, and disbursing payments hereunder. The Administrator’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.

6.    No Mitigation. Payment of the amounts and benefits under Section2(a) and Section 3 (except as otherwise provided in Section 2(a)(6)) shall not be subject to offset, counterclaim, recoupment, defense or other claim, right or action which the Corporation or an Employer may have and shall not be subject to a requirement that Officer mitigate or attempt to mitigate damages resulting from Officer’s termination of employment.

7.    Amendment and Termination. The Corporation, acting through its People and Compensation Committee (or its successor), reserves the right to amend or terminate the Policy at any time; provided, however, that any amendment which would reduce the aggregate level of benefits, or terminate the Policy, shall not become effective prior to the completion of the notice period. Such notice period shall be the first anniversary of the Corporation giving notice to Officers of such amendment or termination.5

8.    Successors. The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Corporation expressly to assume and to agree to perform its obligations under this Policy

5To the extent that Officers are eligible for benefits until this Policy as of November 1, 2021, the Notice Period shall be three years from the receipt of notice that the Notice Period has been reduced to one year.

10

in the same manner and to the same extent that the Corporation would be required to perform such obligations if no such succession had taken place; provided, however, that no such assumption shall relieve the Corporation of its obligations hereunder. As used herein, the “Corporation” shall mean the Corporation as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform its obligations by operation or law or otherwise.

This Policy shall inure to the benefit of and be binding upon the Officer (and Officer’s personal representatives and heirs), Corporation and its successors and assigns, and any such successor or assignee shall be deemed substituted for the Corporation under the terms of this Policy for all purposes. As used herein, “successor” and “assignee” shall include any person, firm, corporation or other business entity which at any time, whether by purchase, merger or otherwise, directly or indirectly acquires the stock of the Corporation or to which the Corporation assigns this Policy by operation of law or otherwise. If Officer should die while any amount would still be payable to Officer hereunder if Officer had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with this Policy to Officer’s devisee, legatee or other designee, or if there is no such designee, to Officer’s estate.

9.    Nonassignability of Benefits. The payments under this Policy or the right to receive future payments under this Policy may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for payments becomes bankrupt, the payments under the Policy of the person affected may be terminated by the Administrator who, in his or her sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that he or she deems appropriate.

10.    Nonguarantee of Employment. Officers covered by the Policy are at-will employees, and nothing contained in this Policy shall be construed as a contract of employment between the Officer and the Corporation (or, where applicable, a subsidiary or affiliate of the Corporation), or as a right of the Officer to continued employment, or to remain as an Officer, or as a limitation on the right of the Corporation (or a subsidiary or affiliate of the Corporation) to discharge Officer at any time, with or without cause.

11.    Benefits Unfunded and Unsecured. The payments under this Policy are unfunded, and the interest under this Policy of any Officer and such Officer’s right to receive payments under this Policy shall be an unsecured claim against the general assets of the Corporation.

12.    Applicable Law. All questions pertaining to the construction, validity, and effect of the Policy shall be determined in accordance with the laws of the United States and, to the extent not preempted by such laws, by the laws of the state of California.

13.    Arbitration. With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Policy, Officer’s employment with the Corporation (or with the employing subsidiary), the termination thereof or any claims for benefits shall be resolved exclusively by final and binding arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making their determination, the arbitrators shall be limited to accepting the position of the Officer or the position of the Corporation, as the case may be. The only claims not covered by this Section 132 are claims for benefits under workers’ compensation or unemployment insurance laws; such claims will be resolved under those laws. The place of arbitration shall be San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The prevailing party in any dispute or controversy covered by this Section 13, or with respect to any request for specific performance, injunctive or other equitable relief, shall be

11

entitled to recover, in addition to any other available remedies specified in this Policy, all litigation expenses and costs, including any arbitrator or administrative or filing fees and reasonable attorneys’ fees. Such expenses, costs and fees, if payable to Officer, shall be paid within 60 days after they are incurred. Both the Officer and the Corporation specifically waive any right to a jury trial on any dispute or controversy covered by this Section 13. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction.

15.    Reimbursements and In-Kind Benefits. Notwithstanding any other provision of this Policy, all reimbursements and in-kind benefits provided under this Policy shall be made or provided in accordance with the requirements of Code Section 409A, including, where applicable, the requirement that (i) the amount of expenses eligible for reimbursement and the provision of benefits in kind during a calendar year shall not affect the expenses eligible for reimbursement or the provision of in-kind benefits in any other calendar year; (ii) the reimbursement for an eligible expense will be made on or before the last day of the calendar year following the calendar year in which the expense is incurred (or by such earlier time set forth in this Policy); (iii) the right to reimbursement or right to in-kind benefit is not subject to liquidation or exchange for another benefit; and (iv) each reimbursement payment or provision of in-kind benefit shall be one of a series of separate payments (and each shall be construed as a separate identified payment) for purposes of Code Section 409A.

15.    Separate Payments. Each payment and benefit under this Policy shall be a “separate payment” for purposes of Code Section 409A.

12

APPENDIX A

PARTICIPATING EMPLOYERS

PG&E Corporation

Pacific Gas and Electric Company

PG&E Corporation Support Services, Inc.

PG&E Corporation Support Services II, Inc.

EX-21

EXHIBIT 21

Significant Subsidiaries

Parent of Significant Subsidiary	Name of Significant Subsidiary	Jurisdiction of Formation of Subsidiary	Names under which Significant Subsidiary does business
PG&E Corporation	Pacific Gas and Electric Company	CA	Pacific Gas and Electric Company
			PG&E
Pacific Gas and Electric Company	None

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-236629-01 on Form S-3, Registration Statement No. 333-253630-01 on Form S-3/ASR, and Registration Statement Nos. 333-129422, 333-176090, 333-195902, 333-206457, 333-239544, and 333-256896 on Form S-8 of our reports dated February 10, 2022, relating to the financial statements of PG&E Corporation and the effectiveness of PG&E Corporation’s internal control over financial reporting appearing in this Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2021.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-236629 on Form S-3 and Registration Statement No. 333-253630 on Form S-3/ASR of our reports dated February 10, 2022, relating to the financial statements of Pacific Gas and Electric Company and the effectiveness of Pacific Gas and Electric Company’s internal control over financial reporting appearing in this Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2021.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

EX-24

EXHIBIT 24

POWER OF ATTORNEY

Each of the undersigned Directors of PG&E Corporation hereby constitutes and appoints JOHN R. SIMON, BRIAN M. WONG, SUJATA PAGEDAR, J. ELLEN CONTI, LISA CRAWFORD, and JENNY KAN, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Annual Report on Form 10-K for the year ended December 31, 2021 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, we have signed these presents this 10th day of February 2022.

/s/ RAJAT BAHRI	/s/ ARNO L. HARRIS
Rajat Bahri	Arno L. Harris
/s/ CHERYL F. CAMPBELL	/s/ MICHAEL R. NIGGLI
Cheryl F. Campbell	Michael R. Niggli
/s/ KERRY W. COOPER	/s/ PATRICIA K. POPPE
Kerry W. Cooper	Patricia K. Poppe
/s/ JESSICA L. DENECOUR	/s/ DEAN L. SEAVERS
Jessica L. Denecour	Dean L. Seavers
/s/ MARK E. FERGUSON, III	/s/ WILLIAM L. SMITH
Mark E. Ferguson, III	William L. Smith
/s/ ROBERT C. FLEXON	/s/ BENJAMIN F. WILSON
Robert C. Flexon	Benjamin F. Wilson
/s/ W. CRAIG FUGATE
W. Craig Fugate

POWER OF ATTORNEY

Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints JOHN R. SIMON, BRIAN M. WONG, SUJATA PAGEDAR, J. ELLEN CONTI, LISA CRAWFORD, and JENNY KAN, and each of them, as his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Annual Report on Form 10-K for the year ended December 31, 2021 required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, we have signed these presents this 10th day of February 2022.

/s/ RAJAT BAHRI	/s/ ARNO L. HARRIS
Rajat Bahri	Arno L. Harris
/s/ CHERYL F. CAMPBELL	/s/ MICHAEL R. NIGGLI
Cheryl F. Campbell	Michael R. Niggli
/s/ KERRY W. COOPER	/s/ PATRICIA K. POPPE
Kerry W. Cooper	Patricia K. Poppe
/s/ JESSICA L. DENECOUR	/s/ DEAN L. SEAVERS
Jessica L. Denecour	Dean L. Seavers
/s/ MARK E. FERGUSON, III	/s/ WILLIAM L. SMITH
Mark E. Ferguson, III	William L. Smith
/s/ ROBERT C. FLEXON	/s/ BENJAMIN F. WILSON
Robert C. Flexon	Benjamin F. Wilson
/s/ W. CRAIG FUGATE	/s/ ADAM L. WRIGHT
W. Craig Fugate	Adam. L. Wright

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

I, Patricia K. Poppe, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2021 of PG&E Corporation;

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

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

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

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

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

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

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

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

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

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

Date: February 10, 2022	/s/ PATRICIA K. POPPE
	Patricia K. Poppe
	Chief Executive Officer

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

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

I, Christopher A. Foster, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2021 of PG&E Corporation;

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

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

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

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

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

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

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

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

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

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

Date: February 10, 2022	/s/ CHRISTOPHER A. FOSTER
	Christopher A. Foster
	Executive Vice President and Chief Financial Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

I, Adam L. Wright, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2021 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: February 10, 2022	/s/ ADAM L. WRIGHT
	Adam L. Wright
	Executive Vice President, Operations and Chief Operating Officer

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

I, Marlene M. Santos, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2021 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: February 10, 2022	/s/ MARLENE M. SANTOS
	Marlene M. Santos
	Executive Vice President and Chief Customer Officer

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

I, Jason M. Glickman, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2021 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: November 1, 2021	/s/ JASON M. GLICKMAN
	Jason M. Glickman
	Executive Vice President, Engineering, Planning, and Strategy

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

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

I, David S. Thomason, certify that:

1.    I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2021 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: February 10, 2022	/s/ DAVID S. THOMASON
	David S. Thomason
	Vice President, Chief Financial Officer and Controller

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2021 (“Form 10-K”), I, Patricia K. Poppe, Chief Executive Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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

/s/ PATRICIA K. POPPE

Patricia K. Poppe

Chief Executive Officer

February 10, 2022

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of PG&E Corporation for the year ended December 31, 2021 (“Form 10-K”), I, Christopher A. Foster, Executive Vice President and Chief Financial Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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

/s/ CHRISTOPHER A. FOSTER

Christopher A. Foster

Executive Vice President and Chief Financial Officer

February 10, 2022

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2021 (“Form 10-K”), I, Adam L. Wright, Executive Vice President, Operations and Chief Operating Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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

/s/ ADAM L. WRIGHT

Adam L. Wright

Executive Vice President, Operations and Chief Operating Officer

February 10, 2022

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2021 (“Form 10-K”), I, Marlene M. Santos, Executive Vice President and Chief Customer Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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

/s/ MARLENE M. SANTOS

Marlene M. Santos

Executive Vice President and Chief Customer Officer

February 10, 2022

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2021 (“Form 10-K”), I, Jason M. Glickman, Executive Vice President, Engineering, Planning, and Strategy of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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

/s/ JASON M. GLICKMAN

Jason M. Glickman

Executive Vice President, Engineering, Planning, and Strategy

February 10, 2022

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-K of Pacific Gas and Electric Company for the year ended December 31, 2021 (“Form 10-K”), I, David S. Thomason, Vice President, Chief Financial Officer and Controller of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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

/s/ DAVID S. THOMASON

David S. Thomason

Vice President, Chief Financial Officer and Controller

February 10, 2022

XML

Cover Page - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2021

Feb. 04, 2022

Jun. 30, 2021

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2021

Current Fiscal Year End Date

--12-31

Document Transition Report

false

Entity File Number

1-12609

Entity Incorporation, State or Country Code

CA

Entity Tax Identification Number

94-3234914

Entity Address, Address Line One

77 Beale Street

Entity Address, Address Line Two

P.O. Box 770000

Entity Address, City or Town

San Francisco,

Entity Address, State or Province

CA

Entity Address, Postal Zip Code

94117

City Area Code

415

Local Phone Number

973-1000

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Entity Shell Company

false

Entity Bankruptcy Proceedings, Reporting Current

true

Entity Public Float

$ 20,185

Entity Common Stock, Shares Outstanding (in shares)

2,463,891,104

Documents Incorporated by Reference

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:

Designated portions of the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

Amendment Flag

false

Document Fiscal Year Focus

2021

Document Fiscal Period Focus

FY

Entity Registrant Name

PG&E CORP

Entity Central Index Key

0001004980

Auditor Name

DELOITTE & TOUCHE LLP

Auditor Firm ID

34

Auditor Location

San Francisco, California

Pacific Gas & Electric Co (Utility)

Document Type

10-K

Entity File Number

1-2348

Entity Incorporation, State or Country Code

CA

Entity Tax Identification Number

94-0742640

Entity Address, Address Line One

77 Beale Street

Entity Address, Address Line Two

P.O. Box 770000

Entity Address, City or Town

San Francisco,

Entity Address, State or Province

CA

Entity Address, Postal Zip Code

94117

City Area Code

415

Local Phone Number

973-1000

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Non-accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Entity Shell Company

false

Entity Bankruptcy Proceedings, Reporting Current

true

Entity Common Stock, Shares Outstanding (in shares)

264,374,809

Documents Incorporated by Reference

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:

Designated portions of the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14)

Entity Registrant Name

PACIFIC GAS & ELECTRIC CO

Entity Central Index Key

0000075488

The New York Stock Exchange | Common stock, no par value

Title of 12(b) Security

Common stock, no par value

Trading Symbol

PCG

Security Exchange Name

NYSE

The New York Stock Exchange | Equity Units

Title of 12(b) Security

Equity Units

Trading Symbol

PCGU

Security Exchange Name

NYSE

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5% series A redeemable

Trading Symbol

PCG-PE

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5% redeemable

Trading Symbol

PCG-PD

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 4.80% redeemable

Trading Symbol

PCG-PG

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 4.50% redeemable

Trading Symbol

PCG-PH

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable

Trading Symbol

PCG-PI

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 6% nonredeemable

Trading Symbol

PCG-PA

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable

Trading Symbol

PCG-PB

Security Exchange Name

NYSEAMER

NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable

Title of 12(b) Security

First preferred stock, cumulative, par value $25 per share, 5% nonredeemable

Trading Symbol

PCG-PC

Security Exchange Name

NYSEAMER

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues
Total operating revenues	$ 20,642	$ 18,469	$ 17,129
Operating Expenses
Operating and maintenance	10,200	8,684	8,725
Wildfire-related claims, net of recoveries	258	251	11,435
Wildfire fund expense	517	413	0
Depreciation, amortization, and decommissioning	3,403	3,468	3,234
Total operating expenses	18,759	16,714	27,223
Operating Income (Loss)	1,883	1,755	(10,094)
Interest income	20	39	82
Interest expense	(1,601)	(1,260)	(934)
Other income, net	457	483	250
Reorganization items, net	(11)	(1,959)	(346)
Income (Loss) Before Income Taxes	748	(942)	(11,042)
Income tax provision (benefit)	836	362	(3,400)
Net Loss	(88)	(1,304)	(7,642)
Preferred stock dividend requirement of subsidiary	14	14	14
Loss Attributable to Common Shareholders	$ (102)	$ (1,318)	$ (7,656)
Weighted Average Common Shares Outstanding, Basic (in shares)	1,985	1,257	528
Weighted Average Common Shares Outstanding, Diluted (in shares)	1,985	1,257	528
Net Loss Per Common Share, Basic (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)
Net Loss Per Common Share, Diluted (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)
Electric
Operating Revenues
Total operating revenues	$ 15,131	$ 13,858	$ 12,740
Operating Expenses
Cost of electricity and natural gas	3,232	3,116	3,095
Natural gas
Operating Revenues
Total operating revenues	5,511	4,611	4,389
Operating Expenses
Cost of electricity and natural gas	$ 1,149	$ 782	$ 734

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Loss	$ (88)	$ (1,304)	$ (7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $7, and $0, at respective dates)	7	(17)	(1)
Total other comprehensive income (loss)	7	(17)	(1)
Comprehensive Loss	(81)	(1,321)	(7,643)
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Loss Attributable to Common Shareholders	$ (95)	$ (1,335)	$ (7,657)

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Pension and other postretirement benefit plans obligations, tax	$ 3	$ 7	$ 0

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 291	$ 484
Restricted Cash	16	143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345	1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207	1,083
Regulatory balancing accounts	2,999	2,001
Other	1,784	1,172
Regulatory assets	496	410
Inventories
Gas stored underground and fuel oil	44	95
Materials and supplies	552	533
Wildfire fund asset	461	464
Other	882	1,334
Total current assets	11,077	9,602
Property, Plant, and Equipment
Electric	69,482	66,982
Gas	25,979	24,135
Construction work in progress	3,479	2,757
Financing lease and other	20	20
Total property, plant, and equipment	98,960	93,894
Accumulated depreciation	(29,134)	(27,758)
Net property, plant, and equipment	69,826	66,136
Other Noncurrent Assets
Regulatory assets	9,207	8,978
Nuclear decommissioning trusts	3,798	3,538
Operating lease right of use asset	1,234	1,741
Wildfire fund asset	5,313	5,816
Income taxes receivable	9	67
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,863	1,978
Total other noncurrent assets	22,424	22,118
TOTAL ASSETS	103,327	97,856
Current Liabilities
Short-term borrowings	2,184	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481	28
Accounts payable
Trade creditors	2,855	2,402
Regulatory balancing accounts	1,121	1,245
Other	679	580
Operating lease liabilities	468	533
Disputed claims and customer refunds	0	242
Interest payable	481	498
Wildfire-related claims	2,722	2,250
Other	2,436	2,256
Total current liabilities	17,427	13,581
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	38,225	37,288
Regulatory liabilities	11,999	10,424
Pension and other postretirement benefits	860	2,444
Asset retirement obligations	5,298	6,412
Deferred income taxes	3,177	1,398
Operating lease liabilities	810	1,208
Other	4,308	3,848
Total noncurrent liabilities	64,677	63,022
Contingencies and Commitments (Notes 14 and 15)
Shareholders' Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,985,400,540 and 1,984,678,673 shares outstanding at respective dates	35,129	30,224
Treasury Stock, at cost; 477,743,590 and 0 shares at respective dates	(4,854)	0
Reinvested earnings	(9,284)	(9,196)
Accumulated other comprehensive loss	(20)	(27)
Total shareholders' equity	20,971	21,001
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	21,223	21,253
TOTAL LIABILITIES AND EQUITY	$ 103,327	$ 97,856

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Allowance for doubtful accounts	$ 171	$ 146
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345	1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207	1,083
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481	28
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	$ 38,225	$ 37,288
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	3,600,000,000	3,600,000,000
Common stock, shares outstanding (in shares)	1,985,400,540	1,984,678,673
Treasury stock, shares at cost (in shares)	477,743,590	0
Variable Interest Entity, Primary Beneficiary
Allowance for doubtful accounts	$ 171	$ 143
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,060	1,630
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,090	959
Net noncurrent accounts receivable	187,000	0
Noncurrent allowance for doubtful accounts	15,000	0
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	18	0
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	$ 1,820	$ 1,000

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities
Net income (loss)	$ (88)	$ (1,304)	$ (7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403	3,468	3,234
Bad Debt Expense	154	150	46
Allowance for equity funds used during construction	(133)	(140)	(79)
Deferred income taxes and tax credits, net	1,783	1,097	(2,948)
Reorganization items, net (Note 2)	(73)	1,458	108
Wildfire fund expense	517	413	0
Disallowed capital expenditures	0	17	581
Other	248	249	161
Effect of changes in operating assets and liabilities:
Accounts receivable	(589)	(1,182)	(104)
Wildfire-related insurance receivable	(723)	1,564	35
Inventories	(32)	6	(80)
Accounts payable	117	58	516
Wildfire-related claims	472	(16,525)	(114)
Income taxes receivable/payable	0	0	23
Other current assets and liabilities	244	(1,079)	77
Regulatory assets, liabilities, and balancing accounts, net	(2,266)	(2,451)	(1,417)
Liabilities subject to compromise	0	413	12,222
Contributions to Wildfire fund	(193)	(5,200)	0
Other noncurrent assets and liabilities	(579)	(142)	197
Net cash provided by (used in) operating activities	2,262	(19,130)	4,816
Cash Flows from Investing Activities
Capital expenditures	(7,689)	(7,690)	(6,313)
Proceeds from sale of the SFGO	749	0	0
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678	1,518	956
Purchases of nuclear decommissioning trust investments	(1,702)	(1,590)	(1,032)
Other	59	14	11
Net cash used in investing activities	(6,905)	(7,748)	(6,378)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	500	1,850
Repayments of debtor-in-possession credit facility	0	(2,000)	(350)
Debtor-in-possession credit facility debt issuance costs	0	(6)	(113)
Bridge facility financing fees	0	(73)	0
Borrowings under credit facilities	9,730	8,554	0
Repayments under credit facilities	(9,976)	(3,949)	0
Credit facilities financing fees	(9)	(22)	0
Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300	1,448	0
Short-term debt matured	(1,450)	0	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $43, $178, and $0 at respective dates	5,474	13,497	0
Repayment of long-term debt	(87)	(764)	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	370	0	0
Exchanged debt financing fees	0	(103)	0
Common stock issued	0	7,582	85
Equity Units issued	0	1,304	0
Other	(29)	(40)	(8)
Net cash provided by financing activities	4,323	25,928	1,464
Net change in cash, cash equivalents, and restricted cash	(320)	(950)	(98)
Cash, cash equivalents, and restricted cash at January 1	627	1,577	1,675
Cash, cash equivalents, and restricted cash at December 31	307	627	1,577
Less: Restricted cash and restricted cash equivalents	(16)	(143)	(7)
Cash and cash equivalents at December 31	291	484	1,570
Cash paid for:
Interest, net of amounts capitalized	(1,404)	(1,563)	(10)
Income taxes, net	99	0	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,311	515	826
Operating lease liabilities arising from obtaining ROU assets	100	13	2,816
Common stock issued in satisfaction of liabilities	0	8,276	0
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement	$ 4,854	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Financing Activities
Issuance costs for short-term debt	$ 1	$ 2	$ 0
Premium, discount, and issuance costs on proceeds from long-term debt	$ 43	$ 178	$ 0

XML

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	PG&E ShareCo Common Stock	Total Shareholders' Equity	Common Stock		Treasury Stock	Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)	Non- controlling Interest - Preferred Stock  of Subsidiary
Beginning balance (in shares) at Dec. 31, 2018				520,338,710
Beginning balance at Dec. 31, 2018	$ 12,903		$ 12,651	$ 12,910			$ (250)	$ (9)	$ 252
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(7,642)		(7,642)				(7,642)
Total other comprehensive income (loss)	(1)		(1)					(1)
Common stock issued, net (in shares)				8,898,031
Common stock issued, net	85		85	$ 85
Stock-based compensation amortization	43		43	$ 43
Ending balance (in shares) at Dec. 31, 2019				529,236,741
Ending balance at Dec. 31, 2019	5,388		5,136	$ 13,038			(7,892)	(10)	252
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,304)		(1,304)				(1,304)
Total other comprehensive income (loss)	(17)		(17)					(17)
Common stock issued, net (in shares)				1,455,441,932
Common stock issued, net	15,854		15,854	$ 15,854
Equity units issued	1,304		1,304	1,304
Stock-based compensation amortization	$ 28		28	$ 28
Ending balance (in shares) at Dec. 31, 2020	1,984,678,673			1,984,678,673
Ending balance at Dec. 31, 2020	$ 21,253		21,001	$ 30,224			(9,196)	(27)	252
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(88)		(88)				(88)
Total other comprehensive income (loss)	7		7					7
Common stock issued, net (in shares)		477,743,590		721,867	[1]
Common stock issued, net	4,854		4,854	$ 4,854
Treasury stock acquired (in shares)						477,743,590
Treasury stock acquired	(4,854)		(4,854)			$ (4,854)
Stock-based compensation amortization	$ 51		51	$ 51
Ending balance (in shares) at Dec. 31, 2021	1,985,400,540			1,985,400,540		477,743,590
Ending balance at Dec. 31, 2021	$ 21,223		$ 20,971	$ 35,129		$ (4,854)	$ (9,284)	$ (20)	$ 252

[1] Excludes 477,743,590 shares of common stock issued to ShareCo. For more information, see Note 6 below.

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CONSOLIDATED STATEMENTS OF INCOME, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues
Total operating revenues	$ 20,642	$ 18,469	$ 17,129
Operating Expenses
Operating and maintenance	10,200	8,684	8,725
Wildfire-related claims, net of recoveries	258	251	11,435
Wildfire fund expense	517	413	0
Depreciation, amortization, and decommissioning	3,403	3,468	3,234
Total operating expenses	18,759	16,714	27,223
Operating Income (Loss)	1,883	1,755	(10,094)
Interest income	20	39	82
Interest expense	(1,601)	(1,260)	(934)
Other income, net	457	483	250
Reorganization items, net	(11)	(1,959)	(346)
Income (Loss) Before Income Taxes	748	(942)	(11,042)
Income tax provision (benefit)	836	362	(3,400)
Net Loss	(88)	(1,304)	(7,642)
Loss Attributable to Common Shareholders	(102)	(1,318)	(7,656)
Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	20,642	18,469	17,129
Operating Expenses
Operating and maintenance	10,194	8,707	8,750
Wildfire-related claims, net of recoveries	258	251	11,435
Wildfire fund expense	517	413	0
Depreciation, amortization, and decommissioning	3,403	3,469	3,233
Total operating expenses	18,753	16,738	27,247
Operating Income (Loss)	1,889	1,731	(10,118)
Interest income	22	39	82
Interest expense	(1,373)	(1,111)	(912)
Other income, net	512	470	239
Reorganization items, net	(12)	(310)	(320)
Income (Loss) Before Income Taxes	1,038	819	(11,029)
Income tax provision (benefit)	900	408	(3,407)
Net Loss	138	411	(7,622)
Preferred stock dividend requirement	14	14	14
Loss Attributable to Common Shareholders	124	397	(7,636)
Electric
Operating Revenues
Total operating revenues	15,131	13,858	12,740
Operating Expenses
Cost of electricity and natural gas	3,232	3,116	3,095
Electric | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	15,131	13,858	12,740
Operating Expenses
Cost of electricity and natural gas	3,232	3,116	3,095
Natural gas
Operating Revenues
Total operating revenues	5,511	4,611	4,389
Operating Expenses
Cost of electricity and natural gas	1,149	782	734
Natural gas | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	5,511	4,611	4,389
Operating Expenses
Cost of electricity and natural gas	$ 1,149	$ 782	$ 734

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net Loss	$ (88)	$ (1,304)	$ (7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations	7	(17)	(1)
Total other comprehensive income (loss)	7	(17)	(1)
Comprehensive Loss	(81)	(1,321)	(7,643)
Pacific Gas & Electric Co (Utility)
Net Loss	138	411	(7,622)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations	(4)	(6)	2
Total other comprehensive income (loss)	(4)	(6)	2
Comprehensive Loss	$ 134	$ 405	$ (7,620)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension and other postretirement benefit plans obligations, tax	$ 3	$ 7	$ 0
Pacific Gas & Electric Co (Utility)
Pension and other postretirement benefit plans obligations, tax	$ 1	$ 2	$ 1

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CONSOLIDATED BALANCE SHEETS, UTILITY - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 291	$ 484
Restricted Cash	16	143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345	1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207	1,083
Regulatory balancing accounts	2,999	2,001
Other	1,784	1,172
Regulatory assets	496	410
Inventories
Gas stored underground and fuel oil	44	95
Materials and supplies	552	533
Wildfire fund asset	461	464
Other	882	1,334
Total current assets	11,077	9,602
Property, Plant, and Equipment
Electric	69,482	66,982
Gas	25,979	24,135
Construction work in progress	3,479	2,757
Financing lease and other	20	20
Total property, plant, and equipment	98,960	93,894
Accumulated depreciation	(29,134)	(27,758)
Net property, plant, and equipment	69,826	66,136
Other Noncurrent Assets
Regulatory assets	9,207	8,978
Nuclear decommissioning trusts	3,798	3,538
Operating lease right of use asset	1,234	1,741
Wildfire fund asset	5,313	5,816
Income taxes receivable	9	67
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,863	1,978
Total other noncurrent assets	22,424	22,118
TOTAL ASSETS	103,327	97,856
Current Liabilities
Short-term borrowings	2,184	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481	28
Accounts payable
Trade creditors	2,855	2,402
Regulatory balancing accounts	1,121	1,245
Other	679	580
Operating lease liabilities	468	533
Disputed claims and customer refunds	0	242
Interest payable	481	498
Wildfire-related claims	2,722	2,250
Other	2,436	2,256
Total current liabilities	17,427	13,581
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	38,225	37,288
Regulatory liabilities	11,999	10,424
Pension and other postretirement benefits	860	2,444
Asset retirement obligations	5,298	6,412
Deferred income taxes	3,177	1,398
Operating lease liabilities	810	1,208
Other	4,308	3,848
Total noncurrent liabilities	64,677	63,022
Contingencies and Commitments (Notes 14 and 15)
Shareholders' Equity
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates	35,129	30,224
Reinvested earnings	(9,284)	(9,196)
Accumulated other comprehensive loss	(20)	(27)
Total shareholders' equity	20,971	21,001
TOTAL LIABILITIES AND EQUITY	103,327	97,856
Pacific Gas & Electric Co (Utility)
Current Assets
Cash and cash equivalents	165	261
Restricted Cash	16	143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345	1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207	1,083
Regulatory balancing accounts	2,999	2,001
Other	1,932	1,180
Regulatory assets	496	410
Inventories
Gas stored underground and fuel oil	44	95
Materials and supplies	552	533
Wildfire fund asset	461	464
Other	869	1,321
Total current assets	11,086	9,374
Property, Plant, and Equipment
Electric	69,482	66,982
Gas	25,979	24,135
Construction work in progress	3,480	2,757
Financing lease and other	18	18
Total property, plant, and equipment	98,959	93,892
Accumulated depreciation	(29,131)	(27,756)
Net property, plant, and equipment	69,828	66,136
Other Noncurrent Assets
Regulatory assets	9,207	8,978
Nuclear decommissioning trusts	3,798	3,538
Operating lease right of use asset	1,232	1,736
Wildfire fund asset	5,313	5,816
Income taxes receivable	7	66
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,706	1,818
Total other noncurrent assets	22,263	21,952
TOTAL ASSETS	103,177	97,462
Current Liabilities
Short-term borrowings	2,184	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,455	0
Accounts payable
Trade creditors	2,853	2,366
Regulatory balancing accounts	1,121	1,245
Other	648	624
Operating lease liabilities	467	530
Disputed claims and customer refunds	0	242
Interest payable	430	444
Wildfire-related claims	2,722	2,250
Other	2,430	2,248
Total current liabilities	17,310	13,496
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	33,632	32,664
Regulatory liabilities	11,999	10,424
Pension and other postretirement benefits	764	2,328
Asset retirement obligations	5,298	6,412
Deferred income taxes	3,409	1,570
Operating lease liabilities	810	1,206
Other	4,345	3,886
Total noncurrent liabilities	60,257	58,490
Contingencies and Commitments (Notes 14 and 15)
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	28,286
Reinvested earnings	(4,247)	(4,385)
Accumulated other comprehensive loss	(9)	(5)
Total shareholders' equity	25,610	25,476
TOTAL LIABILITIES AND EQUITY	$ 103,177	$ 97,462

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Allowance for doubtful accounts	$ 171.0	$ 146.0
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345.0	1,883.0
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207.0	1,083.0
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481.0	28.0
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	$ 38,225.0	$ 37,288.0
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	3,600,000,000	3,600,000,000
Common stock, shares outstanding (in shares)	1,985,400,540	1,984,678,673
Pacific Gas & Electric Co (Utility)
Allowance for doubtful accounts	$ 171.0	$ 146.0
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345.0	1,883.0
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207.0	1,083.0
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,455.0	0.0
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	$ 33,632.0	$ 32,664.0
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	264,374,809	264,374,809
Variable Interest Entity, Primary Beneficiary
Allowance for doubtful accounts	$ 171.0	$ 143.0
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,060.0	1,630.0
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,090.0	959.0
Net noncurrent accounts receivable	187,000.0	0.0
Noncurrent allowance for doubtful accounts	15,000.0	0.0
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	18.0	0.0
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	1,820.0	1,000.0
Variable Interest Entity, Primary Beneficiary | Pacific Gas & Electric Co (Utility)
Allowance for doubtful accounts	171.0	143.0
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,060.0	1,630.0
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,090.0	959.0
Net noncurrent accounts receivable	187,000.0	0.0
Noncurrent allowance for doubtful accounts	15,000.0	0.0
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	18.0	0.0
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	$ 1,820.0	$ 1,000.0

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CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities
Net income (loss)	$ (88)	$ (1,304)	$ (7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403	3,468	3,234
Bad Debt Expense	154	150	46
Allowance for equity funds used during construction	(133)	(140)	(79)
Deferred income taxes and tax credits, net	1,783	1,097	(2,948)
Reorganization items, net (Note 2)	(73)	1,458	108
Wildfire fund expense	517	413	0
Disallowed capital expenditures	0	17	581
Other	248	249	161
Effect of changes in operating assets and liabilities:
Accounts receivable	(589)	(1,182)	(104)
Wildfire-related insurance receivable	(723)	1,564	35
Inventories	(32)	6	(80)
Accounts payable	117	58	516
Wildfire-related claims	472	(16,525)	(114)
Income taxes receivable/payable	0	0	23
Other current assets and liabilities	244	(1,079)	77
Regulatory assets, liabilities, and balancing accounts, net	(2,266)	(2,451)	(1,417)
Liabilities subject to compromise	0	413	12,222
Contributions to Wildfire fund	(193)	(5,200)	0
Other noncurrent assets and liabilities	(579)	(142)	197
Net cash provided by (used in) operating activities	2,262	(19,130)	4,816
Cash Flows from Investing Activities
Capital expenditures	(7,689)	(7,690)	(6,313)
Proceeds from sale of the SFGO	749	0	0
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678	1,518	956
Purchases of nuclear decommissioning trust investments	(1,702)	(1,590)	(1,032)
Other	59	14	11
Net cash used in investing activities	(6,905)	(7,748)	(6,378)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	500	1,850
Repayments of debtor-in-possession credit facility	0	(2,000)	(350)
Debtor-in-possession credit facility debt issuance costs	0	(6)	(113)
Bridge facility financing fees	0	(73)	0
Borrowings under credit facilities	9,730	8,554	0
Repayments under credit facilities	(9,976)	(3,949)	0
Credit facilities financing fees	(9)	(22)	0
Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300	1,448	0
Short-term debt matured	(1,450)	0	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $43, $178, and $0 at respective dates	5,474	13,497	0
Repayment of long-term debt	(87)	(764)	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	370	0	0
Exchanged debt financing fees	0	(103)	0
Other	(29)	(40)	(8)
Net cash provided by financing activities	4,323	25,928	1,464
Net change in cash, cash equivalents, and restricted cash	(320)	(950)	(98)
Cash, cash equivalents, and restricted cash at January 1	627	1,577	1,675
Cash, cash equivalents, and restricted cash at December 31	307	627	1,577
Less: Restricted cash and restricted cash equivalents	(16)	(143)	(7)
Cash and cash equivalents at December 31	291	484	1,570
Cash paid for:
Interest, net of amounts capitalized	(1,404)	(1,563)	(10)
Income taxes, net	99	0	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,311	515	826
Operating lease liabilities arising from obtaining ROU assets	100	13	2,816
Pacific Gas & Electric Co (Utility)
Cash Flows from Operating Activities
Net income (loss)	138	411	(7,622)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403	3,469	3,233
Bad Debt Expense	154	150	46
Allowance for equity funds used during construction	(133)	(140)	(79)
Deferred income taxes and tax credits, net	1,846	1,141	(2,952)
Reorganization items, net (Note 2)	(41)	(90)	97
Wildfire fund expense	517	413	0
Disallowed capital expenditures	0	17	581
Other	172	220	121
Effect of changes in operating assets and liabilities:
Accounts receivable	(584)	(1,160)	(132)
Wildfire-related insurance receivable	(723)	1,564	35
Inventories	(32)	6	(80)
Accounts payable	44	(24)	579
Wildfire-related claims	472	(16,525)	(114)
Income taxes receivable/payable	0	0	5
Other current assets and liabilities	251	(1,141)	101
Regulatory assets, liabilities, and balancing accounts, net	(2,266)	(2,451)	(1,417)
Liabilities subject to compromise	0	401	12,194
Contributions to Wildfire fund	(193)	(5,200)	0
Other noncurrent assets and liabilities	(577)	(108)	214
Net cash provided by (used in) operating activities	2,448	(19,047)	4,810
Cash Flows from Investing Activities
Capital expenditures	(7,689)	(7,690)	(6,313)
Proceeds from sale of the SFGO	749	0	0
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678	1,518	956
Purchases of nuclear decommissioning trust investments	(1,702)	(1,590)	(1,032)
Intercompany note to PG&E Corporation	(145)	0	0
Other	59	14	11
Net cash used in investing activities	(7,050)	(7,748)	(6,378)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	500	1,850
Repayments of debtor-in-possession credit facility	0	(2,000)	(350)
Debtor-in-possession credit facility debt issuance costs	0	(6)	(97)
Bridge facility financing fees	0	(33)	0
Borrowings under credit facilities	9,730	8,554	0
Repayments under credit facilities	(9,976)	(3,949)	0
Credit facilities financing fees	(9)	(22)	0
Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300	1,448	0
Short-term debt matured	(1,450)	0	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $43, $178, and $0 at respective dates	5,474	8,837	0
Repayment of long-term debt	(59)	(100)	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	370	0	0
Exchanged debt financing fees	0	(103)	0
Equity contribution from PG&E Corporation	0	12,986	0
Other	(1)	(42)	(8)
Net cash provided by financing activities	4,379	26,070	1,395
Net change in cash, cash equivalents, and restricted cash	(223)	(725)	(173)
Cash, cash equivalents, and restricted cash at January 1	404	1,129	1,302
Cash, cash equivalents, and restricted cash at December 31	181	404	1,129
Less: Restricted cash and restricted cash equivalents	(16)	(143)	(7)
Cash and cash equivalents at December 31	165	261	1,122
Cash paid for:
Interest, net of amounts capitalized	(1,198)	(1,458)	(7)
Income taxes, net	99	0	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	1,311	515	826
Operating lease liabilities arising from obtaining ROU assets	100	13	2,807
Common stock equity infusion from PG&E Corporation used to satisfy liabilities	$ 0	$ 6,750	$ 0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Financing Activities
Issuance costs for short-term debt	$ 1	$ 2	$ 0
Premium, discount, and issuance costs on proceeds from long-term debt	43	178	0
Pacific Gas & Electric Co (Utility)
Cash Flows from Financing Activities
Issuance costs for short-term debt	1	2	0
Premium, discount, and issuance costs on proceeds from long-term debt	$ 43	$ 88	$ 0

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CONSOLIDATED STATEMENTS OF EQUITY, UTILITY - USD ($) $ in Millions	Total	Pacific Gas & Electric Co (Utility)	Total Shareholders' Equity	Total Shareholders' Equity Pacific Gas & Electric Co (Utility)	Preferred Stock Pacific Gas & Electric Co (Utility)	Common Stock	Common Stock Pacific Gas & Electric Co (Utility)	Additional Paid-in Capital Pacific Gas & Electric Co (Utility)	Reinvested Earnings	Reinvested Earnings Pacific Gas & Electric Co (Utility)	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Pacific Gas & Electric Co (Utility)
Beginning balance at Dec. 31, 2018	$ 12,903		$ 12,651	$ 12,955	$ 258	$ 12,910	$ 1,322	$ 8,550	$ (250)	$ 2,826	$ (9)	$ (1)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(7,642)	$ (7,622)	(7,642)	(7,622)					(7,642)	(7,622)
Total other comprehensive income (loss)	(1)	2	(1)	2							(1)	2
Ending balance at Dec. 31, 2019	5,388		5,136	5,335	258	13,038	1,322	8,550	(7,892)	(4,796)	(10)	1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,304)	411	(1,304)	411					(1,304)	411
Total other comprehensive income (loss)	(17)	(6)	(17)	(6)							(17)	(6)
Equity Contribution				19,736				19,736
Ending balance at Dec. 31, 2020	21,253		21,001	25,476	258	30,224	1,322	28,286	(9,196)	(4,385)	(27)	(5)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(88)	138	(88)	138					(88)	138
Total other comprehensive income (loss)	7	$ (4)	7	(4)							7	(4)
Ending balance at Dec. 31, 2021	$ 21,223		$ 20,971	$ 25,610	$ 258	$ 35,129	$ 1,322	$ 28,286	$ (9,284)	$ (4,247)	$ (20)	$ (9)

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ORGANIZATION AND BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION AND BASIS OF PRESENTATION

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 is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 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 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 Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of 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, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the 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.

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BANKRUPTCY FILING

12 Months Ended

Dec. 31, 2021

Reorganizations [Abstract]

BANKRUPTCY FILING

BANKRUPTCY FILING

Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence 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.

On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020.

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

Unresolved Chapter 11 Claims

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 a trust for the benefit of holders of certain subrogation claims (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 asserted litigation claims, trade creditor 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. Amounts expected to be allowed are reflected as current liabilities in the Consolidated Balance Sheets.

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 Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).

In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 14 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 14 under the heading “Securities Class Action Litigation.”

In addition to filing objections in the Bankruptcy Court to claims with respect to which PG&E Corporation and the Utility do not believe they have liability, PG&E Corporation and the Utility are working to resolve certain disputed general unsecured claims before a panel of mediators. On November 4, 2021, the Bankruptcy Court entered an order extending the deadline for PG&E Corporation and the Utility to object to claims to June 21, 2022, except for a claim filed by the California Department of Water Resources, for which the Bankruptcy Court set an objection deadline of March 23, 2022.

Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings were 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 recover on the Utility’s refund claims against these electricity suppliers. After the Utility received $145 million from the California Power Exchange and various escrows that were established as part of the disputed claims settlements in December 2021, the Utility filed at the Bankruptcy Court to close out its 2001 bankruptcy case. On December 22, 2021, the Bankruptcy Court granted the motion for entry of final decree and closed the 2001 bankruptcy case. As of December 31, 2021, the Consolidated Balance Sheets reflected $0 in net claims within Disputed claims and customer refunds compared to $242 million as of December 31, 2020. The Utility expects to refund current regulatory liabilities of $422 million, reflected in Current liabilities – other on the Consolidated Balance Sheets, $145 million of which would be funded from the amounts received from the California Power Exchange and various escrows discussed above.

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 $31 million and $53 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2021 as compared to $102 million and $400 million for PG&E Corporation and the Utility, respectively, during 2020.

Reorganization items, net for the year ended December 31, 2021 include the following:

	Year Ended December 31, 2021
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	21		(1)		20
Interest and other	(9)		—		(9)
Total reorganization items, net	$	12	$	(1)	$	11

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

Reorganization items, net for the year ended December 31, 2020 include the following:

	Year Ended December 31, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	6	$	—	$	6
Legal and other (2)	318		1,651		1,969
Interest income	(14)		(2)		(16)
Total reorganization items, net	$	310	$	1,649	$	1,959

(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 from the Petition Date through December 31, 2019 include the following:

	Petition Date Through December 31, 2019
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	273		19		292
Interest income	(50)		(10)		(60)
Total reorganization items, net	$	320	$	26	$	346

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, 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.  These differences have no impact on net income.  See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  As of December 31, 2020, the Utility also held restricted cash that primarily consisted of cash held in escrow to be used to pay bankruptcy related professional fees.

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 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 GRCs, which occur every 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 Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility 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:

	Year Ended
(in millions)	2021		2020
Electric
Revenue from contracts with customers
Residential	$	6,089	$	5,523
Commercial	5,042		4,722
Industrial	1,493		1,530
Agricultural	1,565		1,471
Public street and highway lighting	73		69
Other (1)	(84)		(130)
Total revenue from contracts with customers - electric	14,178		13,185
Regulatory balancing accounts (2)	953		673
Total electric operating revenue	$	15,131	$	13,858
Natural gas
Revenue from contracts with customers
Residential	$	2,759	$	2,517
Commercial	713		597
Transportation service only	1,346		1,211
Other (1)	140		61
Total revenue from contracts with customers - gas	4,958		4,386
Regulatory balancing accounts (2)	553		225
Total natural gas operating revenue	5,511		4,611
Total operating revenues	$	20,642	$	18,469

(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.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2021, PG&E Corporation and the Utility have identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates.

As of December 31, 2021, the allowance also included the estimated impact of the CAPP which offers financial assistance from the State of California for eligible customers in the form of a credit to the customer’s bill. The Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received on January 27, 2022.

As of December 31, 2021, the Utility recorded $209 million of long-term accounts receivables as a result of the CPUC’s June 30, 2021 final decision on bill debt relief which offers financial assistance for eligible customers in the form of a 24-month payment plan.

As of December 31, 2021, expected credit losses of $154 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. At December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

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. Wildfire fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 14 below. Wildfire fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of the claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for its available-for-sale debt securities. An impairment may exist if there is an intent to sell or a requirement to sell before recovery of the amortized basis. If such an impairment exists, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of December 31, 2021, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  See “AFUDC” below.  The Utility’s estimated service lives of its property, plant, and equipment were as follows:

	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2021		2020
Electricity generating facilities (1)	5 to 75	$	11,217	$	12,505
Electricity distribution facilities	10 to 70	37,723		34,902
Electricity transmission facilities	15 to 75	15,516		14,414
Natural gas distribution facilities	20 to 60	14,100		12,962
Natural gas transmission and storage facilities	5 to 66	9,067		8,293
Financing lease		18		18
Construction work in progress		3,480		2,757
General plant and other	5 to 50	7,838		8,041
Total property, plant, and equipment		98,959		93,892
Accumulated depreciation		(29,131)		(27,756)
Net property, plant, and equipment (2)		$	69,828	$	66,136

(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below.

(2) Includes $850 million of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below.

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.82% in 2021, 3.76% in 2020, and 3.80% in 2019.  The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $56 million and $133 million during 2021, $35 million and $140 million during 2020, and $55 million and $79 million during 2019.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2021 and 2020, including nuclear decommissioning obligations:

(in millions)	2021		2020
ARO liability at beginning of year	$	6,412	$	5,854
Liabilities incurred in the current period	—		268
Revision in estimated cash flows	(1,378)		53
Accretion	287		265
Liabilities settled	(23)		(28)
ARO liability at end of year	$	5,298	$	6,412

The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding.  In December 2021, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly decreased its ARO liabilities by $1.4 billion. The adjustment was a result of a decrease in estimated costs based on refinements to the site-specific decommissioning analysis. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation accrued was $3.9 billion and $5.1 billion at December 31, 2021 and 2020, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $7.6 billion and $10.6 billion at December 31, 2021 and 2020, respectively.

Disallowance of Plant Costs

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

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC. 

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.

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.  

Consolidated VIEs

Receivables Securitization Program

The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5 below) in October 2020 is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells 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, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets. As of December 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021 and 2020, the SPV had net accounts receivable of $3.3 billion and $2.6 billion, respectively, and outstanding borrowings of $974 million and $1.0 billion, respectively, under the Receivables Securitization Program.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Financing Order for AB 1054, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The recovery bonds are scheduled to pay principal and interest semi-annually on January 15 and July 15 of each year. The final scheduled payment date is July 15, 2046. Amounts owed to bond-holders are included in Long-term debt and Long-term debt, classified as current, on the Consolidated Balance Sheets.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021, PG&E Recovery Funding LLC has outstanding borrowings of $860 million.

Non-Consolidated VIEs

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 was the primary beneficiary of any of these VIEs at December 31, 2021, it 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 December 31, 2021, it did not consolidate any of them.

Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054

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 customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as HFTDs 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).

On the Emergence 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. San Diego Gas & Electric Company and Southern California Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020 and 2021, the Utility made its second and third annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility have seven remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). 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.

As of December 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.1 billion in Other non-current liabilities, $461 million in current assets - Wildfire fund asset, and $5.3 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2021 and December 31, 2020, the Utility recorded amortization and accretion expense of $517 million and $413 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. 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 that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. 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 creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a five-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 have decreased the amortization period to six years. As of December 31, 2021, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by three years assuming greater effectiveness and would decrease the amortization period by two 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 and determination of any amounts required to be reimbursed to the Wildfire Fund, 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, and 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 assess the Wildfire Fund asset for acceleration of the amortization of the asset 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 acceleration of the amortization of the asset 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. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire and $43 million of accelerated amortization, reflected in Wildfire Fund expense.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, and “Contingencies and Commitments” in Notes 14 and 15 below.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2021 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(39)	$	17	$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)	1,007		137		1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)	(1,003)		(136)		(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively) (1)	4		(24)		(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)	2		14		16
Net current period other comprehensive income	6		1		7
Ending balance	$	(33)	$	18	$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details. 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(22)	$	17	$	(5)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively)	(417)		170		(247)
Regulatory account transfer (net of taxes of $155 and $66, respectively)	400		(170)		230
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $1 and $6, respectively)(1)	2		(15)		(13)
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1)	2		5		7
Net current period other comprehensive loss	(17)		—		(17)
Ending balance	$	(39)	$	17	$	(22)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

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

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2021 and 2020.

For the years ended December 31, 2021 and 2020, the Utility made total cash payments, including fixed and variable, of $2.4 billion and $2.5 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements.

At December 31, 2021 and 2020, the Utility’s operating leases had a weighted average remaining lease term of 6.04 years and 5.7 years and a weighted average discount rate of 6.1% and 6.2%, respectively.

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

	Year Ended December 31,
(in millions)	2021		2020
Operating lease fixed cost	$	578	$	679
Operating lease variable cost	1,782		1,852
Total operating lease costs	$	2,360	$	2,531

At December 31, 2021, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2021
2022	$	533
2023	276
2024	118
2025	111
2026	105
Thereafter	444
Total lease payments	1,587
Less imputed interest	(310)
Total	$	1,277

Sale of Transmission Tower Wireless Licenses

On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers.

The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.

The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market additional attachment locations on up to 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.

In addition, the Utility and SBA entered into a Pipeline Cell Site Transaction Agreement pursuant to which the Utility and SBA established terms and conditions for adding additional cell sites under the License Agreement. Pipeline Cell Sites are locations where the Utility was in the process of locating a new Cell Site for a wireless carrier at the close of the transaction.

In exchange for the exclusive license and entry into the License Agreement, SBA paid the Utility $946 million of the purchase price at the closing. On August 15, 2021, the post-closing period ended, and the final purchase price was $947 million, pursuant to the terms of the Transaction Agreement.

The Utility recorded approximately $370 million of the $947 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $947 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement, represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a third-party discounted cash flow model based on business assumptions and estimates to determine the allocation of the purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are included in Other noncurrent liabilities on the Consolidated Balance Sheets.

The Utility recorded the remaining approximately $471 million ($455 million of which was noncurrent) of the sale proceeds to regulatory liabilities, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices.

The financing obligation is amortized through Electric operating revenue and Interest expense on the Consolidated Statements of Income using the effective interest method and the deferred revenue balance is amortized through Electric operating revenue ratably over the 100-year term.

Recently Adopted Accounting Standards

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 adopted this ASU on January 1, 2021. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Government Assistance

In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance, which increases the transparency of government assistance including the disclosure of (1) the types of assistance, (2) an entity’s accounting for the assistance, and (3) the effect of the assistance on an entity’s financial statements. PG&E Corporation and the Utility adopted this ASU as of December 31, 2021. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

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 became effective for PG&E Corporation and the Utility on January 1, 2022 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2021		2020
Pension benefits (1)	$	708	$	2,245	Indefinitely
Environmental compliance costs	1,089		1,112		32 years
Utility retained generation (2)	133		181		6 years
Price risk management	216		204		19 years
Unamortized loss, net of gain, on reacquired debt	37		49		23 years
Catastrophic event memorandum account (3)	1,119		842		1 - 3 years
Wildfire expense memorandum account (4)	347		400		TBD years
Fire hazard prevention memorandum account (5)	75		137		1 - 3 years
Fire risk mitigation memorandum account (6)	44		66		1 - 3 years
Wildfire mitigation plan memorandum account (7)	424		390		1 - 3 years
Deferred income taxes (8)	1,849		908		51 years
Insurance premium costs (9)	207		294		3 - 4 years
Wildfire mitigation balancing account (10)	273		156		1 - 3 years
General rate case memorandum accounts (11)	—		376		1 - 2 years
Vegetation management balancing account (12)	1,411		592		1 - 3 years
COVID-19 pandemic protection memorandum accounts (13)	49		84		TBD years
Other	1,226		942		Various
Total long-term regulatory assets	$	9,207	$	8,978

(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 December 31, 2021 and 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Balance as of December 31, 2021 represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire. Balance as of December 31, 2020 is comprised of incremental wildfire liability insurance premium costs for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is 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 is subject to CPUC review and approval.

(6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through December 31, 2021. Recovery of WMPMA costs is 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 excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2021. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) The GRC memorandum accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered through rates over 22 months, beginning March 1, 2021.

(12) Represents costs from routine vegetation management and EVM activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA for the period January 1, 2020 through December 31, 2021. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.

(13) On April 16, 2020, the CPUC passed a resolution that established the 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 certain residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2021, the Utility had recorded an under-collection of $30 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA was in effect. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2021		2020
Cost of removal obligations (1)	$	7,306	$	6,905
Recoveries in excess of AROs (2)	388		458
Public purpose programs (3)	946		948
Employee benefit plans (4)	1,229		995
Transmission tower wireless licenses (5)	446		—
SFGO sale (6)	343		—
Other	1,341		1,118
Total long-term regulatory liabilities	$	11,999	$	10,424

(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 11 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.

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $446 million, $311 million and $135 million will be refunded to FERC and CPUC jurisdiction customers, respectively. See Note 3 above.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period, beginning in 2022.

Regulatory Balancing Accounts

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

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

	Receivable Balance at December 31,
(in millions)	2021		2020
Gas distribution and transmission	$	—	$	102
Energy procurement	310		413
Public purpose programs	321		292
Fire hazard prevention memorandum account	50		121
Fire risk mitigation memorandum account	14		33
Wildfire mitigation plan memorandum account	67		161
Wildfire mitigation balancing account	91		27
General rate case memorandum accounts	468		313
Vegetation management balancing account	127		115
Insurance premium costs	605		135
Wildfire expense memorandum account	440		—
Residential uncollectibles balancing accounts	127		—
Other	379		289
Total regulatory balancing accounts receivable	$	2,999	$	2,001

	Payable Balance at December 31,
(in millions)	2021		2020
Electric distribution	$	121	$	55
Electric transmission	24		267
Gas distribution and transmission	83		76
Energy procurement	211		158
Public purpose programs	259		410
Nuclear decommissioning adjustment mechanism	137		—
Other	286		279
Total regulatory balancing accounts payable	$	1,121	$	1,245

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case.  Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities.  Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency. The FHPMA tracks costs that protect the public from potential fire hazards. The FRMMA and WMPMA balances track costs that are recoverable within 12 months as requested in the 2020 WMCE application. The WMBA tracks costs associated with wildfire mitigation revenue requirement activities. The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC. The VMBA tracks routine and EVM activities. The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2021, there was $82 million in insurance premium costs recorded in Current regulatory assets. The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022. The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. The nuclear decommissioning adjustment mechanism tracks costs related to the closure of the Diablo Canyon power plant.

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DEBT

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

DEBT

DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2021:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding			Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2026	$	4,000	(1)	$	1,885		$	692	$	1,423
Utility term loan credit facility	October 2022 (2)	1,441		(2)	1,441		(2)	—		—
Utility receivables securitization program (3)	September 2023	1,000		(4)	974			—		—		(4)
PG&E Corporation revolving credit facility	June 2024	500			—			—		500
Total credit facilities		$	6,941		$	4,300		$	692	$	1,923

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

(2 On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022.

(3) On October 5, 2020, the Utility 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 the SPV, a limited liability company wholly owned by the Utility. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023. For more information, see “Variable Interest Entities” in Note 3 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program. As of December 31, 2021, the Receivables Securitization Program had a maximum borrowing base of $974 million and was fully drawn.

Utility

As previously disclosed, on July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.

As previously disclosed, on June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.

As previously disclosed, on July 1, 2020, the Utility entered into a $3.0 billion term loan credit agreement (the “Utility Term Loan Credit Agreement”) comprised of 364-day tranche loans in the aggregate principal amount of $1.5 billion (the “364-Day Tranche Loans”) and 18-month tranche loans in the aggregate principal amount of $1.5 billion (the “18-Month Tranche Loans”). As previously disclosed, the 364-Day Tranche Loans were paid in full on March 11, 2021. The 18-Month Tranche Loans had an initial maturity date of 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.

On October 29, 2021 and on December 31, 2021, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to October 1, 2022. On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022. To the extent that any 18-Month Tranche Loans remain outstanding on April 1, 2022, a fee will be due and owing to the lenders holding such 18-Month Tranche Loans.

PG&E Corporation

As previously disclosed, on July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

As previously disclosed, on June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.

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

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. The intercompany note includes usual and customary provisions for notes of this type. The interest rate on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization, pursuant to AB 1054, for a transaction to finance, using securitization, up to $1.19 billion of fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021, with the final amount to be financed based on the capital expenditures incurred by the Utility prior to the securitization transaction. On June 24, 2021, the CPUC issued a financing order authorizing the issuance of up to approximately $1.2 billion of recovery bonds to recover up to $1.19 billion of fire risk mitigation capital expenditures plus an estimated $13.3 million in related upfront financing costs. On July 6, 2021, the financing order became final and non-appealable.

On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The net proceeds were used to fund fire risk mitigation capital expenditures that have been incurred by the Utility and incurred by PG&E Corporation on behalf of the Utility in 2020 and 2021.

For more information on PG&E Recovery Fund LLC, see “Variable Interest Entities” in Note 3 above.

SB 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers 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.

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 finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact amounts billed to customers, with the proceeds of the securitization used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. In connection with the proposed transaction, the Utility would retire $6.0 billion of Utility debt. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. The decision is being challenged by TURN.

Short-Term Debt Issuance

On November 15, 2021, the Utility completed the sale of $300 million aggregate principal amount of Floating Rate First Mortgage Bonds due November 14, 2022. The proceeds, along with the long-term debt proceeds from the First Mortgage Bonds also issued on November 15, 2021, were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021.

Long-Term Debt Issuances and Redemptions

Utility

In March 2021, the Utility issued (i) $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, (ii) $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and (iii) $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s Term Loan Credit Agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement and (iii) general corporate purposes.

In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On November 15, 2021, the Utility completed the sale of (i) $900 million aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 and (ii) an additional $550 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 (the “2031 Bonds”). The 2031 Bonds are part of the same series of debt securities issued by the Utility in March 2021. The proceeds were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021. The Utility used the remaining net proceeds for general corporate purposes, including the repayment of approximately $300 million of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

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

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2021		December 31, 2020
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,709	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of debt issuance costs		(26)		—
Unamortized discount, net of premium and debt issuance costs		(90)		(85)
Total PG&E Corporation Long-Term Debt		4,593		4,624
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	500		500
2022	1.75%	2,500		2,500
2023	1.37% - 4.25%	3,575		1,175
2024	3.40% - 3.75%	800		800
2025	3.45% - 3.50%	1,475		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 3.30%	2,550		2,550
2028	3.00% - 4.65%	1,975		1,175
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		2,000
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		250
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
Less: current portion, net of debt issuance costs		(2,996)		—
Unamortized discount, net of premium and debt issuance costs		(190)		(182)
Total Utility First Mortgage Bonds		31,816		30,170
Recovery Bonds	1.46% - 2.82%	860		—
Less: current portion		(18)		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2023	variable rate (3)	974		1,000
18-month Term Loan - Stated Maturity: 2022	variable rate (4)	1,441		1,500
Less: current portion		(1,441)		—
Unamortized discount, net of premium and debt issuance costs		—		(6)
Total Utility Long-Term Debt		33,632		32,664
Total PG&E Corporation Consolidated Long-Term Debt		$	38,225	$	37,288

(1) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 3.50% and 5.50%, respectively.

(2) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69% and 1.70%, respectively.

(3) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.30% and 1.57%, respectively.

(4) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 2.38% and 2.44%, respectively.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2021 are reflected in the table below:

(in millions, except interest rates)	2022			2023			2024			2025			2026			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2021	3.50		%	3.50		%	3.50		%	3.50		%	—		%	—		%	3.50		%
Variable rate obligations	$	28		$	28		$	28		$	2,625		$	—		$	—		$	2,709
Utility
Average fixed interest rate	1.75		%	2.26		%	3.60		%	3.47		%	3.10		%	3.90		%	3.49		%
Fixed rate obligations	$	2,500		$	3,575		$	800		$	1,475		$	2,551		$	23,601		$	34,502
Variable interest rate as of December 31, 2021	2.20		%	various (1)			—		%	—		%	—		%	—		%	various (1)
Variable rate obligations	$	1,941		$	974		$	—		$	—		$	—		$	—		$	2,915
Total consolidated debt	$	4,469		$	4,577		$	828		$	4,100		$	2,551		$	25,601		$	42,126

(1) At December 31, 2021, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.30%, 1.69% and 2.38% respectively.

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COMMON STOCK AND SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2021

Common Stock And Share-Based Compensation [Abstract]

COMMON STOCK AND SHARE-BASED COMPENSATION

COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 1,985,400,540 shares of common stock outstanding at December 31, 2021, which excludes 477,743,590 shares of common stock issued to ShareCo.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2021.

Equity Offerings

During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 138 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the equity units purchase contracts and subject to certain adjustments as provided therein. The settlement date of the equity unit purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts.

At the Market Equity Distribution Program

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement.

The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement.

During the year ended December 31, 2021, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement. As of December 31, 2021, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings.

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 DTAs to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent 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). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into an agreement (the “Share Exchange and Tax Matters Agreement”), pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,463,891,104 shares outstanding as of February 4, 2022, only 1,548,403,924 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2022 was 2.98% of the outstanding shares. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares.

As of the date of this report, it is more likely than not that PG&E Corporation has not 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.

Share Exchange and Tax Matters Agreement

In accordance with the Share Exchange and Tax Matters Agreement, the grantor trust election has been filed.

With the grantor trust election, the Utility’s tax deductions occur as and when the Fire Victim Trust pays the fire victims rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. For PG&E Corporation common stock transferred to the Fire Victim Trust, the amount of the tax deduction will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust.

Under the Share Exchange and Tax Matters Agreement, the parties agreed to exchange the 477,743,590 shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan (the “Plan Shares”) for an equal number of newly-issued shares of PG&E Corporation common stock (the “New Shares”). Accordingly, on July 9, 2021, PG&E Corporation issued 477,743,590 New Shares to ShareCo, which has the sole purpose of holding the New Shares in a designated brokerage account to facilitate the exchange process. When the Fire Victim Trust desires to sell any or all of its Plan Shares, the Fire Victim Trust may exchange any number of Plan Shares for a corresponding number of New Shares on a share-for-share basis (without any further consideration payable by either party) and thereafter promptly dispose of the New Shares in one or more transactions with one or more third parties. In the event that the Fire Victim Trust is unable to timely dispose of New Shares under certain circumstances (such shares, the “Nonconforming New Shares”), PG&E Corporation has authorized up to 250,000,000 additional shares of PG&E Corporation common stock, which may be transferred by ShareCo to the Fire Victim Trust on behalf of the Utility, in exchange for the Nonconforming New Shares, following the same procedures as for an exchange of Plan Shares for New Shares. The Plan Shares and any Non-Conforming New Shares exchanged will be held thereafter by the Utility. In the event that the Fire Victim Trust disposes of any share of PG&E Corporation’s common stock subject to the Share Exchange and Tax Matters Agreement without complying with the terms of the agreement, the Fire Victim Trust may be required to make a payment to the Utility designed to compensate the Utility for adverse tax consequences arising from nonconforming sale transactions.

Upon PG&E Corporation’s issuance of the New Shares to ShareCo, PG&E Corporation’s common stock increased by $4.85 billion, the fair value of the shares on July 9, 2021. The increase to common stock is fully offset by the fair value of treasury stock recorded. The issuance of the New Shares did not have an impact on the total number of outstanding common shares as the New Shares are currently held by ShareCo and as such, there was no impact on basic or diluted EPS for the year ended December 31, 2021.

When the Fire Victim Trust notifies the Utility that it intends to sell shares, ShareCo (on behalf of the Utility) will transfer the New Shares to the Fire Victim Trust, and the Fire Victim Trust will transfer the Plan Shares to the Utility. The Utility has no plan or intention to dispose of the Plan Shares at any time. As shares are exchanged with the Fire Victim Trust, the Utility will record the cost of shares and PG&E Corporation’s investment under additional paid in capital and PG&E Corporation’s common stock and treasury stock will decrease by the fair value per share established on July 9, 2021.

As of December 31, 2021, none of the 250,000,000 reserved shares had been issued.

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 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.  As of January 31, 2022, there were $59.1 million of such cumulative and unpaid dividends on the Utility’s preferred stock. 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 emergence 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. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. It is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock.

Long-Term Incentive Plan

The LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 58,552,722 shares were available for future awards at December 31, 2021.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2021:

(in millions)	2021		2020		2019
Stock Options	$	—	$	3	$	7
Restricted stock units	35		15		21
Performance shares	21		17		22
Total compensation expense (pre-tax)	$	56	$	35	$	50
Total compensation expense (after-tax)	$	40	$	25	$	35

Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant.  Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2021, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. No stock options were granted in 2021 and 2020.  

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the date of grant.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2021.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2021:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,221,247	$	7.45		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(25,413)	10.23			—
Outstanding at December 31	2,195,834	7.42		4.33	—
Vested or expected to vest at December 31	2,195,834	7.42		4.33	—
Exercisable at December 31	2,195,834	$	7.42	4.33	$	—

(1) Represents additional payout of existing stock option grants.

Restricted Stock Units

Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2021, 2020, and 2019 was $11.01, $9.25, and $18.57, respectively.  The total fair value of restricted stock units that vested during 2021, 2020, and 2019 was $19 million, $31 million, and $42 million, respectively.  The tax detriment from restricted stock units that vested in 2021 was $11 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2021, $81 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 2.19 years.

The following table summarizes restricted stock unit activity for 2021:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	890,353	$	23.05
Granted	10,352,117	11.01
Vested	(743,672)	25.20
Forfeited	(408,423)	11.67
Nonvested at December 31	10,090,375	$	11.00

Performance Shares

Performance shares generally will vest three years after the grant date.  Following vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR).  Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards.  The weighted average grant-date fair value for performance shares granted during 2021, 2020, and 2019 was $11.83, $9.62, and $15.39 respectively.  The tax detriment from performance shares that vested in 2021 was $19 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2021, $50 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.47 years.

The following table summarizes activity for performance shares in 2021:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	7,288,782	$	9.16
Granted	2,714,645	11.83
Vested	—	—
Forfeited (1)	(1,436,418)	11.35
Nonvested at December 31	8,567,009	$	9.64

(1) Includes performance shares that expired with zero value as performance targets were not met.

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PREFERRED STOCK

12 Months Ended

Dec. 31, 2021

Preferred Stock [Abstract]

PREFERRED STOCK

PREFERRED STOCK

PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share.  At December 31, 2021 and 2020, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share, respectively.  The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

On December 31, 2021, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2021, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022.

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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 (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2021, 2020, and 2019.

	Year Ended December 31,
(in millions, except per share amounts)	2021		2020		2019
Loss attributable to common shareholders	$	(102)	$	(1,318)	$	(7,656)
Weighted average common shares outstanding, basic	1,985		1,257		528
Add incremental shares from assumed conversions:
Employee share-based compensation	—		—		—
Equity Units	—		—		—
Weighted average common share outstanding, diluted	1,985		1,257		528
Total Loss per common share, diluted	$	(0.05)	$	(1.05)	$	(14.50)

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

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INCOME TAXES

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating DTAs and liabilities.  DTAs and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the technical merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. 

Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. 

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2021		2020		2019		2021		2020		2019
Current:
Federal	$	—	$	(26)	$	1	$	—	$	(26)	$	4
State	1		(34)		101		—		(34)		94
Deferred:
Federal	543		258		(2,361)		588		290		(2,363)
State	296		171		(1,136)		316		185		(1,137)
Tax credits	(4)		(7)		(5)		(4)		(7)		(5)
Income tax provision (benefit)	$	836	$	362	$	(3,400)	$	900	$	408	$	(3,407)

The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2021		2020		2021		2020
Deferred income tax assets:
Tax carryforwards	$	5,628	$	7,641	$	5,425	$	7,529
Compensation	185		187		108		109
Wildfire-related claims (1)	1,723		544		1,723		544
Operating lease liability	346		489		346		488
Transmission tower wireless licenses	266		—		266		—
Other (2)	278		212		293		219
Total deferred income tax assets	$	8,426	$	9,073	$	8,161	$	8,889
Deferred income tax liabilities:
Property related basis differences	8,847		8,311		8,835		8,300
Regulatory balancing accounts	1,193		763		1,193		763
Debt financing costs	501		526		501		526
Operating lease right of use asset	346		489		346		488
Income tax regulatory asset (3)	517		254		517		254
Other (4)	199		128		178		128
Total deferred income tax liabilities	$	11,603	$	10,471	$	11,570	$	10,459
Total net deferred income tax liabilities	$	3,177	$	1,398	$	3,409	$	1,570

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service territory over the past several years.

(2) Amounts include benefits, environmental reserve, and customer advances for construction. 

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.

(4) Amount primarily includes an environmental reserve.

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

	PG&E Corporation						Utility
	Year Ended December 31,
	2021		2020		2019		2021		2020		2019
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	31.3		(15.3)		7.5		24.1		19.1		7.5
Effect of regulatory treatment of fixed asset differences (2)	(71.5)		39.0		2.8		(51.6)		(44.9)		2.8
Tax credits	(1.7)		1.5		0.1		(1.2)		(1.7)		0.1
Fire Victim Trust (3)	127.3		(44.9)		—		91.9		51.7		—
Bankruptcy and emergence	—		(37.6)		—		—		2.4		—
Other, net (4)	5.3		(2.1)		(0.6)		2.6		2.2		(0.5)
Effective tax rate	111.7	%	(38.4)	%	30.8	%	86.8	%	49.8	%	30.9	%

(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 2021, 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) The Utility includes an adjustment for a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for 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 in 2020. PG&E Corporation includes the same adjustment as the Utility in 2021 and 2020 as well as a permanent non-deductible equity backstop premium expense in 2020. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively in 2020, accounts for the remaining difference.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs in 2021 and 2020.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2021		2020		2019		2021		2020		2019
Balance at beginning of year	$	437	$	420	$	377	$	437	$	420	$	377
Reductions for tax position taken during a prior year	(23)		(43)		(1)		(23)		(43)		(1)
Additions for tax position taken during the current year	85		60		44		85		60		44
Settlements	(1)		—		—		(1)		—		—
Balance at end of year	$	498	$	437	$	420	$	498	$	437	$	420

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2021 for PG&E Corporation and the Utility was $30 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2021, 2020, and 2019, these amounts were immaterial.

Tax Settlements

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010.

PG&E Corporation’s tax returns have been accepted through 2014 for California income tax purposes. Tax years 2015 and thereafter remain subject to examination by the State of California.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

(in millions)	December 31, 2021		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,600	2031 - 2036
Net operating loss carryforward - Post-2017	17,467		N/A
Tax credit carryforward	144		2029 - 2041
State:
Net operating loss carryforward	$	18,853	2039 - 2041
Tax credit carryforward	122		Various

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

Other Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. At December 31, 2021, it is reasonably possible that within the next 12 months, unrecognized tax benefits will decrease. The amount is not expected to be material.

As of the date of this report, it is more likely than not that PG&E Corporation has not 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 have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. Half of the payment was paid in 2021.

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 Consolidated Financial Statements due to this legislation.

Additionally, as a result of the grantor trust election, the Utility’s tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation’s net operating loss has decreased by approximately $10.0 billion, which will be offset by payments made by the Fire Victim Trust to the fire victims (which totaled approximately $1.67 billion in 2021) and the net activities of the Fire Victim Trust to date. Additionally, there was a $1.3 billion charge, net of tax, decreasing net DTAs for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Consolidated Financial Statements for activity through December 31, 2020. PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact in PG&E Corporation’s and the Utility’s consolidated financial statements for the year ended December 31, 2021. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares. For more information, see Note 6 above.

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DERIVATIVES

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through 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 Consolidated Balance Sheets and 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 Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through 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 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 Consolidated Balance Sheets at fair value. 

Volume of Derivative Activity

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

		Contract Volume
		At December 31,
Underlying Product	Instruments	2021	2020
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	173,361,635	146,642,863
	Options	14,420,000	14,140,000
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	10,283,639	9,435,830
	Options	288,000	—
	Congestion Revenue Rights (3)	239,857,610	266,091,470

(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 December 31, 2021, 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	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

At December 31, 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	$	33	$	—	$	115	$	148
Other noncurrent assets – other	136		—		—		136
Current liabilities – other	(38)		—		15		(23)
Noncurrent liabilities – other	(204)		—		10		(194)
Total commodity risk	$	(73)	$	—	$	140	$	67

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

Some 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. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2021, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

	Fair Value Measurements
	At December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	289	$	—	$	—	$	—	$	289
Nuclear decommissioning trusts
Short-term investments	22		—		—		—		22
Global equity securities	2,504		—		—		—		2,504
Fixed-income securities	1,158		866		—		—		2,024
Assets measured at NAV	—		—		—		—		31
Total nuclear decommissioning trusts (2)	3,684		866		—		—		4,581
Price risk management instruments (Note 10)
Electricity	—		9		214		6		229
Gas	—		4		—		137		141
Total price risk management instruments	—		13		214		143		370
Rabbi trusts
Fixed-income securities	—		104		—		—		104
Life insurance contracts	—		76		—		—		76
Total rabbi trusts	—		180		—		—		180
Long-term disability trust
Short-term investments	6		—		—		—		6
Assets measured at NAV	—		—		—		—		132
Total long-term disability trust	6		—		—		—		138
TOTAL ASSETS	$	3,979	$	1,059	$	214	$	143	$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	11	$	248	$	(24)	$	235
Gas	—		10		—		(3)		7
TOTAL LIABILITIES	$	—	$	21	$	248	$	(27)	$	242

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

(2) Represents amount before deducting $783 million, primarily related to deferred taxes on appreciation of investment value. 

	Fair Value Measurements
	At December 31, 2020
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	470	$	—	$	—	$	—	$	470
Nuclear decommissioning trusts
Short-term investments	27		—		—		—		27
Global equity securities	2,398		—		—		—		2,398
Fixed-income securities	924		835		—		—		1,759
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,349		835		—		—		4,209
Price risk management instruments (Note 10)
Electricity	—		2		166		2		170
Gas	—		1		—		113		114
Total price risk management instruments	—		3		166		115		284
Rabbi trusts
Fixed-income securities	—		106		—		—		106
Life insurance contracts	—		79		—		—		79
Total rabbi trusts	—		185		—		—		185
Long-term disability trust
Short-term investments	9		—		—		—		9
Assets measured at NAV	—		—		—		—		158
Total long-term disability trust	9		—		—		—		167
TOTAL ASSETS	$	3,828	$	1,023	$	166	$	115	$	5,315
Liabilities:
Price risk management instruments (Note 10)
Electricity	—		1		238		(25)		214
Gas	—		3		—		—		3
TOTAL LIABILITIES	$	—	$	4	$	238	$	(25)	$	217

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

(2) Represents amount before deducting $671 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 years ended December 31, 2021 and 2020.

Trust Assets

Assets Measured at Fair Value

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

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

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

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the 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, credit 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.  The Utility 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 rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  See Note 10 above.

	Fair Value at
(in millions)	At December 31, 2021				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	188	$	93	Market approach	CRR auction prices	$ (40.77) - 2,265.94 / 0.40
Power purchase agreements	$	26	$	155	Discounted cash flow	Forward prices	$ (7.97) - 256.20 / 47.17

(1) Represents price per megawatt-hour.

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

	Fair Value at
(in millions)	At December 31, 2020				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	153	$	74	Market approach	CRR auction prices	$ (320.25) - 320.25 / 0.30
Power purchase agreements	$	13	$	164	Discounted cash flow	Forward prices	$ 12.56 - 148.30 / 35.52

(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 price risk management instruments for the years ended December 31, 2021 and 2020, respectively:

	Price Risk Management Instruments
(in millions)	2021		2020
Asset (liability) balance as of January 1	$	(72)	$	5
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	38		(77)
Asset (liability) balance as of December 31	$	(34)	$	(72)

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

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2021 and 2020, 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 December 31,
	2021				2020
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,619	$	4,796	$	1,901	$	2,175
Utility	31,816		35,803		29,664		32,632

Nuclear Decommissioning Trust Investments

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

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments	$	22	$	—	$	—	$	22
Global equity securities	479		2,066		(10)		2,535
Fixed-income securities	1,938		98		(12)		2,024
Total (1)	$	2,439	$	2,164	$	(22)	$	4,581
As of December 31, 2020
Nuclear decommissioning trusts
Short-term investments	$	27	$	—	$	—	$	27
Global equity securities	543		1,881		(1)		2,423
Fixed-income securities	1,610		152		(3)		1,759
Total (1)	$	2,180	$	2,033	$	(4)	$	4,209

(1) Represents amounts before deducting $783 million and $671 million at December 31, 2021 and 2020, 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)	December 31, 2021
Less than 1 year	$	97
1–5 years	495
5–10 years	480
More than 10 years	952
Total maturities of fixed-income securities	$	2,024

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

(in millions)	2021		2020		2019
Proceeds from sales and maturities of nuclear decommissioning investments	$	1,678	$	1,518	$	956
Gross realized gains on securities	286		159		69
Gross realized losses on securities	(19)		(41)		(14)

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2021

Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  Certain trusts underlying these plans are qualified trusts under the IRC.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  On an annual basis, the Utility funds the pension plan up to the amount it is authorized to recover through rates.

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2021 and 2020:

Pension Plan

(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	20,759	$	18,547
Actual return on plan assets	1,693		2,736
Company contributions	335		343
Benefits and expenses paid	(892)		(867)
Fair value of plan assets at end of year	$	21,895	$	20,759
Change in benefit obligation:
Benefit obligation at beginning of year	$	23,172	$	20,525
Service cost for benefits earned	587		530
Interest cost	645		713
Actuarial (gain) loss (1)	(752)		2,271
Plan amendments	—		—
Benefits and expenses paid	(893)		(867)
Benefit obligation at end of year (2)	$	22,759	$	23,172
Funded Status:
Current liability	$	(9)	$	(3)
Noncurrent liability	(856)		(2,410)
Net liability at end of year	$	(865)	$	(2,413)

(1) The actuarial gain for the year ended December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions. The actuarial loss for the year ended December 31, 2020 was due to a decrease in the discount rate used to measure the projected benefit obligation.

(2) PG&E Corporation’s accumulated benefit obligation was $20.4 billion and $20.7 billion at December 31, 2021 and 2020, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,995	$	2,678
Actual return on plan assets	193		379
Company contributions	10		26
Plan participant contribution	80		81
Benefits and expenses paid	(176)		(169)
Fair value of plan assets at end of year	$	3,102	$	2,995
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,876	$	1,832
Service cost for benefits earned	63		61
Interest cost	51		63
Actuarial gain (1)	(152)		(14)
Benefits and expenses paid	(156)		(149)
Federal subsidy on benefits paid	4		3
Plan participant contributions	80		80
Benefit obligation at end of year	$	1,766	$	1,876
Funded Status: (2)
Noncurrent asset	$	1,340	$	1,153
Noncurrent liability	(4)		(34)
Net asset at end of year	$	1,336	$	1,119

(1) The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes. The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation.

(2) At December 31, 2021 and 2020, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $363 million and $359 million as of December 31, 2021, and $377 million and $343 million as of December 31, 2020, respectively.

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

Components of Net Periodic Benefit Cost

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.

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan

(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	587	$	530	$	443
Interest cost	645		713		758
Expected return on plan assets	(1,046)		(1,044)		(906)
Amortization of prior service cost	(6)		(6)		(6)
Amortization of net actuarial loss	6		3		3
Net periodic benefit cost	186		196		292
Less: transfer to regulatory account (2)	147		136		42
Total expense recognized	$	333	$	332	$	334

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

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions

(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	63	$	61	$	56
Interest cost	51		63		76
Expected return on plan assets	(137)		(138)		(123)
Amortization of prior service cost	14		14		14
Amortization of net actuarial loss	(33)		(21)		(3)
Net periodic benefit cost	$	(42)	$	(21)	$	20

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

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

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

Components of Accumulated Other Comprehensive Income

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions.  For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income.  For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income.  As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

Valuation Assumptions

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2021		2020		2019		2021	2020	2019
Discount rate	3.03	%	2.77	%	3.46	%	2.97 - 3.04%	2.67 - 2.80 %	3.37 - 3.47%
Rate of future compensation increases	3.80	%	3.80	%	3.90	%	N/A	N/A	N/A
Expected return on plan assets	5.50	%	5.10	%	5.70	%	3.30 - 6.40%	3.10 - 6.10 %	3.50 - 6.60%
Interest crediting rate for cash balance plan	1.95	%	1.95	%	2.11	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2021 was 6.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond. 

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 5.5% compares to a ten-year actual return of 9.6%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 817 Aa-grade non-callable bonds at December 31, 2021.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility.  In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios. 

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

	Pension Plan						PBOP Plans
	2022		2021		2020		2022		2021		2020
Global equity securities	30	%	30	%	30	%	26	%	36	%	28	%
Absolute return	2	%	2	%	2	%	1	%	1	%	2	%
Real assets	8	%	8	%	8	%	3	%	5	%	8	%
Fixed-income securities	60	%	60	%	60	%	70	%	58	%	62	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2021 and 2020. 

	Fair Value Measurements
	At December 31,
	2021								2020
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	552	$	255	$	—	$	807	$	334	$	408	$	—	$	742
Global equity securities	2,074		424		—		2,498		1,875		—		—		1,875
Absolute Return	—		1		—		1		1		1		—		2
Real assets	632		—		—		632		517		—		—		517
Fixed-income securities	2,729		7,388		27		10,144		2,467		7,154		12		9,633
Assets measured at NAV	—		—		—		7,972		—		—		—		8,224
Total	$	5,987	$	8,068	$	27	$	22,054	$	5,194	$	7,563	$	12	$	20,993
PBOP Plans:
Short-term investments	$	31	$	—	$	—	$	31	$	37	$	—	$	—	$	37
Global equity securities	105		—		—		105		173		—		—		173
Real assets	34		—		—		34		54		—		—		54
Fixed-income securities	776		875		1		1,652		481		715		1		1,197
Assets measured at NAV	—		—		—		1,296		—		—		—		1,549
Total	$	946	$	875	$	1	$	3,118	$	745	$	715	$	1	$	3,010
Total plan assets at fair value							$	25,172							$	24,003

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $175 million and $249 million at December 31, 2021 and 2020, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. 

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a NAV per share can be redeemed quarterly with a notice not to exceed 90 days.

Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity Securities

The global equity category includes investments in common stock and equity-index futures.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Real Assets

The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. 

Fixed-Income Securities

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt 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 trusts 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 Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2021 and 2020.

Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2021 and 2020:

(in millions)
For the year ended December 31, 2021	Fixed-Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date	6
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	22
Settlements	(6)
Balance at end of year	$	27
(in millions)
For the year ended December 31, 2020	Fixed-Income
Balance at beginning of year	$	15
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(3)
Purchases, issuances, sales, and settlements:
Purchases	11
Settlements	(13)
Balance at end of year	$	12

There were no material transfers out of Level 3 in 2021 and 2020.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $335 million to the pension benefit plans and $10 million to the other benefit plans in 2021.  These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements.  None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2021.  The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2022. 

Benefits Payments and Receipts

As of December 31, 2021, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2022	869	81	(3)
2023	954	85	(3)
2024	988	89	(3)
2025	1018	88	(3)
2026	1,046	91	(3)
Thereafter in the succeeding five years	5,533	466	(3)

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $133 million, $119 million, and $109 million in 2021, 2020, and 2019, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

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RELATED PARTY AGREEMENTS AND TRANSACTIONS

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

RELATED PARTY AGREEMENTS AND TRANSACTIONS

RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves.  The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services.  PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies.  Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2021		2020		2019
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	4
Utility expenses from:
Administrative services received from PG&E Corporation	$	82	$	108	$	107
Utility employee benefit due to PG&E Corporation	39		34		42

At December 31, 2021 and 2020, the Utility had receivables of $173 million and $35 million, respectively, from PG&E Corporation included in Accounts receivable – other and Noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $19 million and $46 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet. For more information, see “Intercompany Note Payable” in Note 5 above.

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WILDFIRE-RELATED CONTINGENCIES

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES

Liability Overview

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 (including those during mediations with claimants), 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.

The process for estimating losses associated with potential claims related to wildfires 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, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the 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 courts or other governmental entities.

Criminal charges have been filed against the Utility in connection with the 2019 Kincade fire and the 2020 Zogg fire. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. In the event that the Utility were convicted of certain charges in connection with the 2019 Kincade fire or 2020 Zogg fire, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with such fire would materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the courts presiding over the criminal proceedings.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints 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 relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, 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 through rates. 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. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and 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 in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts 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 and the outcome of the criminal proceedings initiated against the Utility. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of 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 the possession of Cal Fire or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. 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 July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

On April 6, 2021, the Sonoma County District Attorney’s office filed the Kincade Complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Kincade Complaint. It further announced that it would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the Kincade Complaint. At a hearing on September 9, 2021, the Sonoma County Superior Court overruled the demurrer. The Utility pled not guilty to all charges on October 13, 2021. On January 28, 2022, the Sonoma County District Attorney’s Office filed the Kincade Amended Complaint, which replaces two felonies with five different felonies and drops six misdemeanor counts. On January 28, 2022, the court deemed the Utility’s demurrer and the court’s prior ruling as applying to 22 of the 30 counts in the Kincade Amended Complaint, and the Utility thereafter pled not guilty to all charges in the Kincade Amended Complaint. A preliminary hearing on the charges began on February 8, 2022.

On December 2, 2021, the CPUC approved a settlement between the Safety Enforcement Division and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that (i) the Utility will pay $40 million to California’s General Fund; (ii) the Utility will remove permanently abandoned transmission lines over a ten-year period; and (iii) the Utility must incur $85 million of the costs of such work by December 31, 2024, and it may not seek recovery of this $85 million of costs. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In connection with the Kincade SED Settlement, PG&E Corporation and the Utility recorded a liability of $40 million reflected in Other current liabilities on the Consolidated Financial Statements for the period ended December 31, 2021. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility expects to record such disallowances in 2022. On January 10, 2022, TURN filed an application for rehearing of the Kincade SED Settlement. On January 25, 2022, the Utility filed an opposition to the application for rehearing.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 2,605 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. In addition, on January 5, 2022, Cal Fire filed a complaint in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. Following a November 5, 2021 hearing, the San Francisco County Superior Court set a trial date of November 7, 2022.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 liability in the aggregate amount of $625 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of PG&E Corporation’s and the Utility’s Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain subrogation entities, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance).

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	625
Payments	—
Balance at December 31, 2020	625
Accrued Losses	175
Payments	(31)
Balance at December 31, 2021	$	769

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, 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. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office filed the Zogg Complaint charging the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges in the Zogg Complaint. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts contained in the Zogg Complaint. A hearing on the demurrer is set for April 4, 2022.

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.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 21 complaints on behalf of at least 382 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. At an October 4, 2021 hearing, the San Francisco County Superior Court set a trial date of February 6, 2023. In addition, PG&E Corporation and the Utility have been contacted by Cal Fire to accept service of a complaint filed against them for fire suppression costs incurred in connection with the 2020 Zogg fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of the Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain agencies, subrogation entities, and individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2020 Zogg fire in the amount of $100 million, for an aggregate liability of $375 million (before available insurance). Following continued negotiations during the quarter ended December 31, 2021, PG&E Corporation and the Utility entered agreements with all but one of the insurance subrogation plaintiffs in the 2020 Zogg fire litigation to resolve their claims arising from the 2020 Zogg fire.

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	275
Payments	—
Balance at December 31, 2020	275
Accrued Losses	100
Payments	(164)
Balance at December 31, 2021	$	211

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. As of December 31, 2021, the Utility has recorded an insurance receivable for $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $22 million in legal fees incurred. Recovery under the Utility’s insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount.

2021 Dixie Fire

According to Cal Fire, on July 13, 2021, at approximately 5:15 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service territory of the Utility. According to a Cal Fire incident update, dated October 25, 2021, 7:46 a.m. Pacific Time, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,329 structures destroyed (including 717 residential, 143 commercial, and 443 other structures), 95 structures damaged, and one fatality, which according to published reports was a fire fighter who passed away due to COVID-19 after returning home from the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility.

The Butte County, Plumas County, Shasta County, Lassen County and Tehama County District Attorneys’ Offices, as well as the SED and OEIS, are investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. 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 2021 Dixie fire. This investigation is ongoing, 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.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 20 complaints on behalf of at least 1,005 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion for the year ended December 31, 2021 (before available recoveries).

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable due to the incomplete information available to PG&E Corporation and the Utility as of the date of this filing as to facts pertinent to potential claims and defenses. Moreover, PG&E Corporation and the Utility are currently unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the National Interagency Coordination Center Incident Management Situation Report dated October 29, 2021 at 7:30 a.m. Mountain Time, over $630 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility currently estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The Utility has liability insurance coverage for third-party liability attributable to periods in which both the 2020 Zogg fire and 2021 Dixie fire occurred in an aggregate amount of $900 million. Recovery under the Utility’s insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount. An immaterial decrease was recorded in the fourth quarter of 2021. As of December 31, 2021, the Utility has recorded an insurance receivable of $563 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $337 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2021, the Utility has recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire. See “Wildfire Fund under AB 1054” below. The Utility has also recorded a $101 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $347 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. An immaterial increase was recorded in the fourth quarter of 2021.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. 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.

Total probable recoveries for the 2021 Dixie fire as of December 31, 2021 are:

Potential Recovery Source (in millions)	2021 Dixie fire
Insurance	$	563
FERC TO rates	101
WEMA	347
Wildfire Fund	150
Probable recoveries at December 31, 2021	$	1,161

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described herein, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period from April 13, 2021 to April 1, 2022, and approximately $32 million in incremental wildfire liability reinsurance for the period from April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire liability reinsurance for the period from July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period from August 1, 2020 to August 1, 2021. On August 1, 2021, the $600 million of existing wildfire liability coverage renewed on a 12-month term covering the period from August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In June 2021, the Utility purchased approximately $535 million in non-wildfire liability coverage for the period from June 1, 2021 to April 1, 2022 at a cost of approximately $89 million. This coverage is in addition to approximately $140 million in existing non-wildfire liability insurance for the period from August 1, 2020 to August 1, 2021. In connection with the June 2021 renewal, the Utility procured an extension of this existing coverage to April 1, 2022 at a premium cost of approximately $30 million. The Utility also has $50 million in additional non-wildfire liability coverage available through one of its wildfire liability policies with shared limits. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million. As of December 31, 2021, PG&E Corporation and the Utility had prepaid insurance of $358 million, reflected in Other current assets on the Consolidated Balance Sheets.

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.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2021, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, and $563 million for probable insurance recoveries in connection with the 2021 Dixie fire. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

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

Insurance Receivable (in millions)	2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	—	$	—	$	1,380	$	808	$	50	$	2,238
Accrued insurance recoveries	—		219		430		—		—		—		649
Reimbursements	—		—		—		(1,380)		(783)		(50)		(2,213)
Balance at December 31, 2020	—		219		430		—		25		—		674
Accrued insurance recoveries (1)	563		118		—		—		—		—		681
Reimbursements (2)	—		(67)		(16)		—		(25)		—		(108)
Balance at December 31, 2021	$	563	$	270	$	414	$	—	$	—	$	—	$	1,247

(1) During the fourth quarter of 2021, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase for the 2020 Zogg fire for $6.5 million.

(2) On January 26, 2022, the Utility received $43 million of insurance reimbursements related to the 2020 Zogg fire.

Regulatory Recovery

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through the FERC TO formula rate in future rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire, for the year ended December 31, 2021, the Utility recorded a $101 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

In June 2018, the CPUC approved the establishment of the WEMA, which provides for tracking of incremental wildfire claims and outside legal costs plus incremental insurance premium costs above what is being recovered through rates. For the year ended December 31, 2021, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire were determined to be probable of recovery and the Utility recorded a $347 million regulatory asset in the WEMA.

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. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. 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 Coverage 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. The accrued Wildfire Fund receivable as of December 31, 2021 reflects an expectation that the Coverage Year will be based on the calendar year with coverage limited to the 2021 Dixie Fire. For 2022, PG&E Corporation and the Utility have elected a Coverage Year that commences on January 1, 2022 at 12:01 a.m. Pacific Time and ends on December 31, 2022 at 12:00 a.m. Pacific Time.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery applying the prudency standard in AB 1054, not to be just and reasonable, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $2.9 billion based on its 2021 equity rate base, and is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar year period. 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 in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund. The Utility expects that the same prudency standard would also be applied in any CPUC review of an application filed by the Utility seeking recovery of costs recorded to the WEMA.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to 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. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 14, 2021, the OEIS (then the Wildfire Safety Division of the CPUC) approved the Utility’s 2020 application and issued the Utility’s 2020 safety certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On January 31, 2022, the OEIS approved the Utility’s 2021 application and issued the Utility’s 2021 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 customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. For more information see “Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 3 above.

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. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed 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.

As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

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 then-current and former members of the boards of directors and certain then-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 denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). 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 related to the 2017 Northern California wildfires 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 the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan. 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 or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action. The assignment became effective as of the Emergence Date. On November 12, 2020, the trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter, to which the parties later stipulated. On March 8, 2021, the court granted the parties’ stipulation to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter 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 then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff 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. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility is a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint. On November 8, 2021, the Court entered an order sustaining in part and overruling in part the demurrers. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint. Trial is set for June 27, 2022.

On January 25, 2019, a separate 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 then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A stipulation and proposed order to voluntarily dismiss this action was filed on April 20, 2021 and a case management conference on the dismissal order is set for March 9, 2022.

The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these 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 or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California (the “District Court”), naming PG&E Corporation and certain of its then-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 Exchange Act 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, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, 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 then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

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 former 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 under submission with the District Court. The securities actions have been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with any such claims submitted through a proof of claim to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases. On April 29, 2021, the District Court issued a notice of intent to stay this action pending completion of the claims procedures in the bankruptcy proceedings. PERA filed objections to the notice of intent to stay on May 28, 2021. PG&E Corporation and the Utility filed a response to PERA’s objections on June 10, 2021, the officer, director, and underwriter defendants filed a response to PERA’s objections on June 11, 2021, and PERA filed a sur-response on June 21, 2021. The District Court has not taken further action with respect to its notice of intent to stay.

Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility relating to, among others, 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. 18-03509, 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 separate 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, which comprises two separate classes under the Plan, 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 with respect to 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 any such allowed 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, 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 Emergence 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 Emergence 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, 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 financial condition, results of operations, liquidity, 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 Emergence 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. PERA has filed two motions seeking approval from the Bankruptcy Court to treat its proof of claim as a class claim. On February 27, 2020 and January 26, 2021, the Bankruptcy Court issued orders denying the motions. PERA filed an appeal of the February 27, 2020 order and on March 8, 2021, the District Court issued an order dismissing the appeal.

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 August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the Ninth Circuit Court of Appeals and on December 15, 2021, PERA filed its opening brief. PERA’s appeal to the Ninth Circuit remains pending.

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 help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have been working to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by requesting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Based on discussions with certain holders of the HoldCo Rescission or Damage Claims, PG&E Corporation believes it is probable that it will incur a loss in connection with the HoldCo Rescission or Damage Claims. As of the date of this filing, PG&E Corporation determined that the amount or range of such loss is not reasonably estimable because either a negotiated resolution would be contingent upon available insurance coverage, the scope of which has not yet been agreed, or any negotiated resolutions would be limited to a subset of immaterial claims. PG&E Corporation is further unable to estimate the amount or range of loss because the nature and value of HoldCo Rescission or Damage Claims varies significantly among potential claimholders, and as of the date of this filing, PG&E Corporation has only engaged in substantive discussions with a limited subset of claimholders.

PG&E Corporation and the Utility continue to believe it is reasonably possible that they will incur a loss in connection with the Subordinated Debt Claims but are unable to reasonably estimate the amount or range of loss because the nature and value, if any, of such claims varies significantly among potential claimholders. As of December 31, 2021, PG&E Corporation and the Utility have not recorded a liability in connection with the Subordinated Claims.

De-energization Securities 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 then-current director and certain then-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 PSPS events, 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 Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a current officer of PG&E Corporation as defendants, and removed claims against certain current and former officers of PG&E Corporation previously named in the action.

On February 16, 2021, the plaintiffs filed a motion with the District Court for preliminary approval of a proposed settlement. On November 2, 2021, the District Court entered an order granting final approval of the settlement, which is now effective. Pursuant to the settlement stipulation: (1) PG&E Corporation paid $10 million, and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) released the Released Persons (as defined in the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulation of settlement.

Indemnification Obligations and Directors’ and Officers’ Insurance Coverage

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 certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” 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 litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with the carriers regarding, among other things, the applicability of multiple years of directors’ and officers’ insurance policies to those matters. Recovery under the directors’ and officers’ insurance policies in one such litigation matter will impact the directors’ and officers’ insurance proceeds available in the other matters.

On March 17, 2021, the trustee for the Fire Victim Trust filed a lawsuit entitled Trotter v. PG&E Corporation, et al., in San Francisco Superior Court, seeking, among other things, a declaration that the trustee for the Fire Victim Trust be permitted to participate in the arbitration with the carriers. The trustee named PG&E Corporation, the Utility, and the insurance carriers as defendants. On March 25, 2021, PG&E Corporation and the Utility removed the action to the Bankruptcy Court. On March 29, 2021, the Fire Victim Trust filed a motion to remand the lawsuit back to state court, which the Bankruptcy Court denied on April 20, 2021. On April 30, 2021, the Fire Victim Trust moved for summary judgment. Oppositions and cross-motions to the summary judgment motion were filed by PG&E Corporation, the Utility and the insurance carriers on May 21, 2021. On June 22, 2021, the Bankruptcy Court entered an order denying the Fire Victim Trust’s motion for summary judgment and granting the defendants’ cross-motions for summary judgment. On June 29, 2021, the Bankruptcy Court entered judgment in favor of all defendants and against the Fire Victim Trust.

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, among other things.

The extent of PG&E Corporation’s and the Utility’s recovery of the directors’ and officers’ insurance proceeds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

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.

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 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 pleaded 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).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Court continued the hearing to February 25, 2022.

Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) 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 has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.40 billion in cash that was contributed on the Emergence Date, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million that was paid in cash on January 18, 2022, in each case pursuant to the terms of the tax benefits payment agreement between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Emergence Date, subject to potential adjustments.

OTHER CONTINGENCIES AND COMMITMENTSPG&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 and the Utility 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 and the Utility have financial commitments described in “Other 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 had the ability to impose additional probation conditions on the Utility. On January 25, 2022, the period of probation expired.

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, Commission General Orders 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 the Coalition of California Utility Employees jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. The settlement agreement became effective on the Emergence Date.

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 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 recorded $1.625 billion of the disallowed costs for the year ended December 31, 2020.

(in millions)
Description (1)	Expense		Capital		Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)	$	236	$	—	$	236
Transmission Safety Inspections and Repairs Expense (TO) (2)	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)	—		84		84
Total	$	1,222	$	403	$	1,625

(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.

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

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 and the amount of disallowance can be reasonably estimated.

The Utility expects additional system enhancement spending pursuant to the settlement agreement to 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 (iv) limits the tax savings that must be returned to customers 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. The CPUC approved the decision different on May 7, 2020.

As it relates to the additional $198 million in disallowed costs as adopted in the decision different, the Utility has recorded the full amount, primarily in the WMPMA through December 31, 2021.

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, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, 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. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are currently being held in abeyance until the FERC addresses the ROE issue.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2021 by approximately $324 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility has recorded approximately $197 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the 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 the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

2018 CEMA Interim Rate Relief Subject to Refund

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented commencing on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund.

On November 2, 2021, the Utility filed a settlement agreement with the active parties in the matter. The settlement agreement, if approved by the CPUC, would authorize the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount has already been collected in interim rates. The interim rates would become final and no longer subject to refund. The remainder of the authorized revenue requirement that has yet to be collected would be amortized over a 12-month period.

2020 WMCE Interim Rate Relief Subject to Refund

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 “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California wildfires and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

As previously disclosed, on October 23, 2020, the CPUC approved $447 million in interim rate relief (which includes interest) pertaining to costs addressed in the 2020 WMCE application. All of the costs presented in the 2020 WMCE application are subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.

The costs addressed in the 2020 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’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility filed a motion with the CPUC seeking approval of a settlement agreement that would authorize the Utility to continue to recover an interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this hearing to April 1, 2022.

Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit

In its final decision 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 recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit.

On July 31, 2020, the Utility filed an application seeking recovery of $416.3 million in 2015 to 2022 revenue associated with $512 million of recorded capital expenditures. On July 7, 2021, the Utility filed a joint motion to adopt a settlement agreement reached with the active parties in the proceeding. If approved by the CPUC, the settlement agreement would resolve all issues in this proceeding and would authorize a $356.3 million revenue requirement for the period of 2015 through 2022. Of this amount, $313.3 million of revenues for the period 2015 through 2021 would be amortized in rates over 60 months and $43 million associated with 2022 would be amortized in rates over 12 months through an annual gas true-up filing for rates effective January 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application would be included in test year 2023 rate base in the Utility’s consolidated 2023 GRC. No party submitted comments on the settlement.

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

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 $77 million and $144 million as of December 31, 2021 and December 31, 2020, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. 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. On March 30, 2020, the Bankruptcy Court granted the Utility’s motion to dismiss this class action because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. The appellant filed its opening brief on June 25, 2021. A former executive director of the CPUC filed an amicus brief on July 2, 2021, asking the Ninth Circuit Court of Appeals to reverse the decision of the District Court and to remand the case for further proceedings. The answering brief of PG&E Corporation and the Utility was filed August 25, 2021. On September 1, 2021, the CPUC filed an amicus brief asking the Ninth Circuit Court of Appeals to affirm the District Court’s dismissal. The appellant’s reply brief was filed on October 15, 2021. A panel of the Ninth Circuit Court of Appeals heard oral argument on the plaintiff’s appeal on January 12, 2022.

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

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement.

Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded a charge during the fourth quarter ended December 31, 2021 for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2021		December 31, 2020
Topock natural gas compressor station	$	299	$	303
Hinkley natural gas compressor station	123		132
Former MGP sites owned by the Utility or third parties (1)	667		659
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites (2)	104		111
Fossil fuel-fired generation facilities and sites (3)	70		96
Total environmental remediation liability	$	1,263	$	1,301

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, 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 MGP 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 as of December 31, 2021, 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. As of December 31, 2021, the Utility expected to recover $982 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

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 $220 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 through 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 2022. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 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 $477 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 through 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 $50 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 through 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 $43 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, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages. Additional coverage is procured through EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.

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 $42 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.6 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.6 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

Diablo Canyon Outages

Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator occurred during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. During July 2020 through April 2021, the Utility implemented effective corrective actions. The Utility continues to monitor the affected component.

If additional shutdowns occur in the future, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC in the 2021 Energy Resource Recovery Account compliance proceeding.

PG&E Corporation and the Utility do not currently believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2021:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2022	$	2,062	$	530	$	61	$	823	$	42	$	3,518
2023	2,043		425		61		191		41		2,761
2024	2,020		282		61		157		27		2,547
2025	2,009		216		61		157		—		2,443
2026	1,948		204		21		140		—		2,313
Thereafter	19,310		539		19		52		—		19,920
Total purchase commitments	$	29,392	$	2,196	$	284	$	1,520	$	110	$	33,502

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  As of December 31, 2021, renewable energy contracts expire at various dates between 2022 and 2041.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2022 and 2041.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2021, QF contracts in operation expire at various dates between 2022 and 2041.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity amounted to $3.0 billion in 2021, $2.9 billion in 2020, and $3.0 billion in 2019.

Natural Gas Supply, Transportation, and Storage Commitments 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2022 and 2041.  In addition, the Utility has contracted for natural gas storage services in Northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $1.2 billion in 2021, $0.8 billion in 2020, and $0.9 billion in 2019.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2022 and 2024 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. 

Payments for nuclear fuel amounted to $79 million in 2021, $111 million in 2020, and $74 million in 2019.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2022 and 2052.  At December 31, 2021, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2022	$	43
2023	65
2024	81
2025	77
2026	74
Thereafter	2,938
Total minimum lease payments	$	3,278

Payments for other commitments amounted to $50 million in 2021, $45 million in 2020, and $48 million in 2019.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

Oakland Headquarters Lease

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly-owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.

The term of the Lease will begin on or about April 8, 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 requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants 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.

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 expects to 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.

At December 31, 2021, the Lease had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

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OTHER CONTINGENCIES AND COMMITMENTS

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

OTHER CONTINGENCIES AND COMMITMENTS

WILDFIRE-RELATED CONTINGENCIES

Liability Overview

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 (including those during mediations with claimants), 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.

The process for estimating losses associated with potential claims related to wildfires 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, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the 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 courts or other governmental entities.

Criminal charges have been filed against the Utility in connection with the 2019 Kincade fire and the 2020 Zogg fire. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. In the event that the Utility were convicted of certain charges in connection with the 2019 Kincade fire or 2020 Zogg fire, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with such fire would materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the courts presiding over the criminal proceedings.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints 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 relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, 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 through rates. 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. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and 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 in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts 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 and the outcome of the criminal proceedings initiated against the Utility. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of 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 the possession of Cal Fire or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. 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 July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

On April 6, 2021, the Sonoma County District Attorney’s office filed the Kincade Complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Kincade Complaint. It further announced that it would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the Kincade Complaint. At a hearing on September 9, 2021, the Sonoma County Superior Court overruled the demurrer. The Utility pled not guilty to all charges on October 13, 2021. On January 28, 2022, the Sonoma County District Attorney’s Office filed the Kincade Amended Complaint, which replaces two felonies with five different felonies and drops six misdemeanor counts. On January 28, 2022, the court deemed the Utility’s demurrer and the court’s prior ruling as applying to 22 of the 30 counts in the Kincade Amended Complaint, and the Utility thereafter pled not guilty to all charges in the Kincade Amended Complaint. A preliminary hearing on the charges began on February 8, 2022.

On December 2, 2021, the CPUC approved a settlement between the Safety Enforcement Division and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that (i) the Utility will pay $40 million to California’s General Fund; (ii) the Utility will remove permanently abandoned transmission lines over a ten-year period; and (iii) the Utility must incur $85 million of the costs of such work by December 31, 2024, and it may not seek recovery of this $85 million of costs. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In connection with the Kincade SED Settlement, PG&E Corporation and the Utility recorded a liability of $40 million reflected in Other current liabilities on the Consolidated Financial Statements for the period ended December 31, 2021. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility expects to record such disallowances in 2022. On January 10, 2022, TURN filed an application for rehearing of the Kincade SED Settlement. On January 25, 2022, the Utility filed an opposition to the application for rehearing.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 2,605 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. In addition, on January 5, 2022, Cal Fire filed a complaint in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. Following a November 5, 2021 hearing, the San Francisco County Superior Court set a trial date of November 7, 2022.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 liability in the aggregate amount of $625 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of PG&E Corporation’s and the Utility’s Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain subrogation entities, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance).

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	625
Payments	—
Balance at December 31, 2020	625
Accrued Losses	175
Payments	(31)
Balance at December 31, 2021	$	769

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, 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. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office filed the Zogg Complaint charging the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges in the Zogg Complaint. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts contained in the Zogg Complaint. A hearing on the demurrer is set for April 4, 2022.

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.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 21 complaints on behalf of at least 382 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. At an October 4, 2021 hearing, the San Francisco County Superior Court set a trial date of February 6, 2023. In addition, PG&E Corporation and the Utility have been contacted by Cal Fire to accept service of a complaint filed against them for fire suppression costs incurred in connection with the 2020 Zogg fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of the Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain agencies, subrogation entities, and individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2020 Zogg fire in the amount of $100 million, for an aggregate liability of $375 million (before available insurance). Following continued negotiations during the quarter ended December 31, 2021, PG&E Corporation and the Utility entered agreements with all but one of the insurance subrogation plaintiffs in the 2020 Zogg fire litigation to resolve their claims arising from the 2020 Zogg fire.

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	275
Payments	—
Balance at December 31, 2020	275
Accrued Losses	100
Payments	(164)
Balance at December 31, 2021	$	211

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. As of December 31, 2021, the Utility has recorded an insurance receivable for $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $22 million in legal fees incurred. Recovery under the Utility’s insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount.

2021 Dixie Fire

According to Cal Fire, on July 13, 2021, at approximately 5:15 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service territory of the Utility. According to a Cal Fire incident update, dated October 25, 2021, 7:46 a.m. Pacific Time, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,329 structures destroyed (including 717 residential, 143 commercial, and 443 other structures), 95 structures damaged, and one fatality, which according to published reports was a fire fighter who passed away due to COVID-19 after returning home from the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility.

The Butte County, Plumas County, Shasta County, Lassen County and Tehama County District Attorneys’ Offices, as well as the SED and OEIS, are investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. 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 2021 Dixie fire. This investigation is ongoing, 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.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 20 complaints on behalf of at least 1,005 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the 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 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion for the year ended December 31, 2021 (before available recoveries).

The Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable due to the incomplete information available to PG&E Corporation and the Utility as of the date of this filing as to facts pertinent to potential claims and defenses. Moreover, PG&E Corporation and the Utility are currently unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the National Interagency Coordination Center Incident Management Situation Report dated October 29, 2021 at 7:30 a.m. Mountain Time, over $630 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility currently estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The Utility has liability insurance coverage for third-party liability attributable to periods in which both the 2020 Zogg fire and 2021 Dixie fire occurred in an aggregate amount of $900 million. Recovery under the Utility’s insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount. An immaterial decrease was recorded in the fourth quarter of 2021. As of December 31, 2021, the Utility has recorded an insurance receivable of $563 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $337 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2021, the Utility has recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire. See “Wildfire Fund under AB 1054” below. The Utility has also recorded a $101 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $347 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA. An immaterial increase was recorded in the fourth quarter of 2021.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. 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.

Total probable recoveries for the 2021 Dixie fire as of December 31, 2021 are:

Potential Recovery Source (in millions)	2021 Dixie fire
Insurance	$	563
FERC TO rates	101
WEMA	347
Wildfire Fund	150
Probable recoveries at December 31, 2021	$	1,161

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described herein, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period from April 13, 2021 to April 1, 2022, and approximately $32 million in incremental wildfire liability reinsurance for the period from April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire liability reinsurance for the period from July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period from August 1, 2020 to August 1, 2021. On August 1, 2021, the $600 million of existing wildfire liability coverage renewed on a 12-month term covering the period from August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In June 2021, the Utility purchased approximately $535 million in non-wildfire liability coverage for the period from June 1, 2021 to April 1, 2022 at a cost of approximately $89 million. This coverage is in addition to approximately $140 million in existing non-wildfire liability insurance for the period from August 1, 2020 to August 1, 2021. In connection with the June 2021 renewal, the Utility procured an extension of this existing coverage to April 1, 2022 at a premium cost of approximately $30 million. The Utility also has $50 million in additional non-wildfire liability coverage available through one of its wildfire liability policies with shared limits. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million. As of December 31, 2021, PG&E Corporation and the Utility had prepaid insurance of $358 million, reflected in Other current assets on the Consolidated Balance Sheets.

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.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2021, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, and $563 million for probable insurance recoveries in connection with the 2021 Dixie fire. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

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

Insurance Receivable (in millions)	2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	—	$	—	$	1,380	$	808	$	50	$	2,238
Accrued insurance recoveries	—		219		430		—		—		—		649
Reimbursements	—		—		—		(1,380)		(783)		(50)		(2,213)
Balance at December 31, 2020	—		219		430		—		25		—		674
Accrued insurance recoveries (1)	563		118		—		—		—		—		681
Reimbursements (2)	—		(67)		(16)		—		(25)		—		(108)
Balance at December 31, 2021	$	563	$	270	$	414	$	—	$	—	$	—	$	1,247

(1) During the fourth quarter of 2021, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase for the 2020 Zogg fire for $6.5 million.

(2) On January 26, 2022, the Utility received $43 million of insurance reimbursements related to the 2020 Zogg fire.

Regulatory Recovery

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through the FERC TO formula rate in future rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire, for the year ended December 31, 2021, the Utility recorded a $101 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

In June 2018, the CPUC approved the establishment of the WEMA, which provides for tracking of incremental wildfire claims and outside legal costs plus incremental insurance premium costs above what is being recovered through rates. For the year ended December 31, 2021, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire were determined to be probable of recovery and the Utility recorded a $347 million regulatory asset in the WEMA.

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. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. 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 Coverage 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. The accrued Wildfire Fund receivable as of December 31, 2021 reflects an expectation that the Coverage Year will be based on the calendar year with coverage limited to the 2021 Dixie Fire. For 2022, PG&E Corporation and the Utility have elected a Coverage Year that commences on January 1, 2022 at 12:01 a.m. Pacific Time and ends on December 31, 2022 at 12:00 a.m. Pacific Time.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery applying the prudency standard in AB 1054, not to be just and reasonable, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $2.9 billion based on its 2021 equity rate base, and is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar year period. 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 in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund. The Utility expects that the same prudency standard would also be applied in any CPUC review of an application filed by the Utility seeking recovery of costs recorded to the WEMA.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to 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. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 14, 2021, the OEIS (then the Wildfire Safety Division of the CPUC) approved the Utility’s 2020 application and issued the Utility’s 2020 safety certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On January 31, 2022, the OEIS approved the Utility’s 2021 application and issued the Utility’s 2021 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 customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. For more information see “Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 3 above.

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. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed 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.

As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

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 then-current and former members of the boards of directors and certain then-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 denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). 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 related to the 2017 Northern California wildfires 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 the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan. 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 or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action. The assignment became effective as of the Emergence Date. On November 12, 2020, the trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter, to which the parties later stipulated. On March 8, 2021, the court granted the parties’ stipulation to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter 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 then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff 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. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility is a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint. On November 8, 2021, the Court entered an order sustaining in part and overruling in part the demurrers. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint. Trial is set for June 27, 2022.

On January 25, 2019, a separate 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 then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A stipulation and proposed order to voluntarily dismiss this action was filed on April 20, 2021 and a case management conference on the dismissal order is set for March 9, 2022.

The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these 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 or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California (the “District Court”), naming PG&E Corporation and certain of its then-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 Exchange Act 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, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, 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 then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

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 former 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 under submission with the District Court. The securities actions have been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with any such claims submitted through a proof of claim to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases. On April 29, 2021, the District Court issued a notice of intent to stay this action pending completion of the claims procedures in the bankruptcy proceedings. PERA filed objections to the notice of intent to stay on May 28, 2021. PG&E Corporation and the Utility filed a response to PERA’s objections on June 10, 2021, the officer, director, and underwriter defendants filed a response to PERA’s objections on June 11, 2021, and PERA filed a sur-response on June 21, 2021. The District Court has not taken further action with respect to its notice of intent to stay.

Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility relating to, among others, 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. 18-03509, 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 separate 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, which comprises two separate classes under the Plan, 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 with respect to 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 any such allowed 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, 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 Emergence 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 Emergence 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, 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 financial condition, results of operations, liquidity, 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 Emergence 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. PERA has filed two motions seeking approval from the Bankruptcy Court to treat its proof of claim as a class claim. On February 27, 2020 and January 26, 2021, the Bankruptcy Court issued orders denying the motions. PERA filed an appeal of the February 27, 2020 order and on March 8, 2021, the District Court issued an order dismissing the appeal.

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 August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the Ninth Circuit Court of Appeals and on December 15, 2021, PERA filed its opening brief. PERA’s appeal to the Ninth Circuit remains pending.

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 help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have been working to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by requesting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Based on discussions with certain holders of the HoldCo Rescission or Damage Claims, PG&E Corporation believes it is probable that it will incur a loss in connection with the HoldCo Rescission or Damage Claims. As of the date of this filing, PG&E Corporation determined that the amount or range of such loss is not reasonably estimable because either a negotiated resolution would be contingent upon available insurance coverage, the scope of which has not yet been agreed, or any negotiated resolutions would be limited to a subset of immaterial claims. PG&E Corporation is further unable to estimate the amount or range of loss because the nature and value of HoldCo Rescission or Damage Claims varies significantly among potential claimholders, and as of the date of this filing, PG&E Corporation has only engaged in substantive discussions with a limited subset of claimholders.

PG&E Corporation and the Utility continue to believe it is reasonably possible that they will incur a loss in connection with the Subordinated Debt Claims but are unable to reasonably estimate the amount or range of loss because the nature and value, if any, of such claims varies significantly among potential claimholders. As of December 31, 2021, PG&E Corporation and the Utility have not recorded a liability in connection with the Subordinated Claims.

De-energization Securities 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 then-current director and certain then-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 PSPS events, 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 Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a current officer of PG&E Corporation as defendants, and removed claims against certain current and former officers of PG&E Corporation previously named in the action.

On February 16, 2021, the plaintiffs filed a motion with the District Court for preliminary approval of a proposed settlement. On November 2, 2021, the District Court entered an order granting final approval of the settlement, which is now effective. Pursuant to the settlement stipulation: (1) PG&E Corporation paid $10 million, and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) released the Released Persons (as defined in the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulation of settlement.

Indemnification Obligations and Directors’ and Officers’ Insurance Coverage

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 certain directors and officers in the securities class actions and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” 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 litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with the carriers regarding, among other things, the applicability of multiple years of directors’ and officers’ insurance policies to those matters. Recovery under the directors’ and officers’ insurance policies in one such litigation matter will impact the directors’ and officers’ insurance proceeds available in the other matters.

On March 17, 2021, the trustee for the Fire Victim Trust filed a lawsuit entitled Trotter v. PG&E Corporation, et al., in San Francisco Superior Court, seeking, among other things, a declaration that the trustee for the Fire Victim Trust be permitted to participate in the arbitration with the carriers. The trustee named PG&E Corporation, the Utility, and the insurance carriers as defendants. On March 25, 2021, PG&E Corporation and the Utility removed the action to the Bankruptcy Court. On March 29, 2021, the Fire Victim Trust filed a motion to remand the lawsuit back to state court, which the Bankruptcy Court denied on April 20, 2021. On April 30, 2021, the Fire Victim Trust moved for summary judgment. Oppositions and cross-motions to the summary judgment motion were filed by PG&E Corporation, the Utility and the insurance carriers on May 21, 2021. On June 22, 2021, the Bankruptcy Court entered an order denying the Fire Victim Trust’s motion for summary judgment and granting the defendants’ cross-motions for summary judgment. On June 29, 2021, the Bankruptcy Court entered judgment in favor of all defendants and against the Fire Victim Trust.

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, among other things.

The extent of PG&E Corporation’s and the Utility’s recovery of the directors’ and officers’ insurance proceeds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

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.

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 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 pleaded 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).

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Court continued the hearing to February 25, 2022.

Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) 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 has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.40 billion in cash that was contributed on the Emergence Date, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million that was paid in cash on January 18, 2022, in each case pursuant to the terms of the tax benefits payment agreement between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Emergence Date, subject to potential adjustments.

OTHER CONTINGENCIES AND COMMITMENTSPG&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 and the Utility 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 and the Utility have financial commitments described in “Other 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 had the ability to impose additional probation conditions on the Utility. On January 25, 2022, the period of probation expired.

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, Commission General Orders 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 the Coalition of California Utility Employees jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. The settlement agreement became effective on the Emergence Date.

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 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 recorded $1.625 billion of the disallowed costs for the year ended December 31, 2020.

(in millions)
Description (1)	Expense		Capital		Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)	$	236	$	—	$	236
Transmission Safety Inspections and Repairs Expense (TO) (2)	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)	—		84		84
Total	$	1,222	$	403	$	1,625

(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.

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

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 and the amount of disallowance can be reasonably estimated.

The Utility expects additional system enhancement spending pursuant to the settlement agreement to 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 (iv) limits the tax savings that must be returned to customers 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. The CPUC approved the decision different on May 7, 2020.

As it relates to the additional $198 million in disallowed costs as adopted in the decision different, the Utility has recorded the full amount, primarily in the WMPMA through December 31, 2021.

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, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, 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. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are currently being held in abeyance until the FERC addresses the ROE issue.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2021 by approximately $324 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility has recorded approximately $197 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the 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 the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

2018 CEMA Interim Rate Relief Subject to Refund

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented commencing on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund.

On November 2, 2021, the Utility filed a settlement agreement with the active parties in the matter. The settlement agreement, if approved by the CPUC, would authorize the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount has already been collected in interim rates. The interim rates would become final and no longer subject to refund. The remainder of the authorized revenue requirement that has yet to be collected would be amortized over a 12-month period.

2020 WMCE Interim Rate Relief Subject to Refund

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 “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California wildfires and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

As previously disclosed, on October 23, 2020, the CPUC approved $447 million in interim rate relief (which includes interest) pertaining to costs addressed in the 2020 WMCE application. All of the costs presented in the 2020 WMCE application are subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.

The costs addressed in the 2020 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’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility filed a motion with the CPUC seeking approval of a settlement agreement that would authorize the Utility to continue to recover an interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this hearing to April 1, 2022.

Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit

In its final decision 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 recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit.

On July 31, 2020, the Utility filed an application seeking recovery of $416.3 million in 2015 to 2022 revenue associated with $512 million of recorded capital expenditures. On July 7, 2021, the Utility filed a joint motion to adopt a settlement agreement reached with the active parties in the proceeding. If approved by the CPUC, the settlement agreement would resolve all issues in this proceeding and would authorize a $356.3 million revenue requirement for the period of 2015 through 2022. Of this amount, $313.3 million of revenues for the period 2015 through 2021 would be amortized in rates over 60 months and $43 million associated with 2022 would be amortized in rates over 12 months through an annual gas true-up filing for rates effective January 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application would be included in test year 2023 rate base in the Utility’s consolidated 2023 GRC. No party submitted comments on the settlement.

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

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 $77 million and $144 million as of December 31, 2021 and December 31, 2020, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. 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. On March 30, 2020, the Bankruptcy Court granted the Utility’s motion to dismiss this class action because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. The appellant filed its opening brief on June 25, 2021. A former executive director of the CPUC filed an amicus brief on July 2, 2021, asking the Ninth Circuit Court of Appeals to reverse the decision of the District Court and to remand the case for further proceedings. The answering brief of PG&E Corporation and the Utility was filed August 25, 2021. On September 1, 2021, the CPUC filed an amicus brief asking the Ninth Circuit Court of Appeals to affirm the District Court’s dismissal. The appellant’s reply brief was filed on October 15, 2021. A panel of the Ninth Circuit Court of Appeals heard oral argument on the plaintiff’s appeal on January 12, 2022.

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

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement.

Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility recorded a charge during the fourth quarter ended December 31, 2021 for an amount that is not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	December 31, 2021		December 31, 2020
Topock natural gas compressor station	$	299	$	303
Hinkley natural gas compressor station	123		132
Former MGP sites owned by the Utility or third parties (1)	667		659
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites (2)	104		111
Fossil fuel-fired generation facilities and sites (3)	70		96
Total environmental remediation liability	$	1,263	$	1,301

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, 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 MGP 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 as of December 31, 2021, 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. As of December 31, 2021, the Utility expected to recover $982 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

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 $220 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 through 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 2022. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 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 $477 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 through 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 $50 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 through 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 $43 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, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages. Additional coverage is procured through EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.

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 $42 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.6 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.6 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

Diablo Canyon Outages

Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator occurred during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. During July 2020 through April 2021, the Utility implemented effective corrective actions. The Utility continues to monitor the affected component.

If additional shutdowns occur in the future, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC in the 2021 Energy Resource Recovery Account compliance proceeding.

PG&E Corporation and the Utility do not currently believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2021:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2022	$	2,062	$	530	$	61	$	823	$	42	$	3,518
2023	2,043		425		61		191		41		2,761
2024	2,020		282		61		157		27		2,547
2025	2,009		216		61		157		—		2,443
2026	1,948		204		21		140		—		2,313
Thereafter	19,310		539		19		52		—		19,920
Total purchase commitments	$	29,392	$	2,196	$	284	$	1,520	$	110	$	33,502

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  As of December 31, 2021, renewable energy contracts expire at various dates between 2022 and 2041.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2022 and 2041.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2021, QF contracts in operation expire at various dates between 2022 and 2041.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity amounted to $3.0 billion in 2021, $2.9 billion in 2020, and $3.0 billion in 2019.

Natural Gas Supply, Transportation, and Storage Commitments 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2022 and 2041.  In addition, the Utility has contracted for natural gas storage services in Northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $1.2 billion in 2021, $0.8 billion in 2020, and $0.9 billion in 2019.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2022 and 2024 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. 

Payments for nuclear fuel amounted to $79 million in 2021, $111 million in 2020, and $74 million in 2019.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2022 and 2052.  At December 31, 2021, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2022	$	43
2023	65
2024	81
2025	77
2026	74
Thereafter	2,938
Total minimum lease payments	$	3,278

Payments for other commitments amounted to $50 million in 2021, $45 million in 2020, and $48 million in 2019.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

Oakland Headquarters Lease

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly-owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million.

The term of the Lease will begin on or about April 8, 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 requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants 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.

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 expects to 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.

At December 31, 2021, the Lease had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

12 Months Ended

Dec. 31, 2021

Condensed Financial Information Disclosure [Abstract]

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Years Ended December 31,
(in millions, except per share amounts)	2021		2020		2019
Administrative service revenue	$	118	$	127	$	138
Operating expenses	(124)		(103)		(114)
Interest income	—		—		1
Interest expense	(230)		(149)		(21)
Other income (expense)	(54)		13		10
Reorganization items, net	1		(1,649)		(26)
Equity in earnings of subsidiaries	137		411		(7,622)
Loss before income taxes	(152)		(1,350)		(7,634)
Income tax provision (benefit)	(64)		(46)		8
Net loss	$	(88)	$	(1,304)	$	(7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $7, and $0, at respective dates)	$	7	$	(17)	$	(1)
Total other comprehensive income (loss)	7		(17)		(1)
Comprehensive Loss	$	(81)	$	(1,321)	$	(7,643)
Weighted Average Common Shares Outstanding, Basic (1)	2,463		1,257		528
Weighted Average Common Shares Outstanding, Diluted (1)	2,463		1,257		528
Net loss per common share, basic	$	(0.05)	$	(1.05)	$	(14.50)
Net loss per common share, diluted	$	(0.05)	$	(1.05)	$	(14.50)

(1) Includes 477,743,590 shares of common stock issued to ShareCo.

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED BALANCE SHEETS

	Balance at December 31,
(in millions)	2021		2020
ASSETS
Current Assets
Cash and cash equivalents	$	126	$	223
Advances to affiliates	21		48
Income taxes receivable	10		12
Other current assets	12		13
Total current assets	169		296
Noncurrent Assets
Equipment	2		2
Accumulated depreciation	(2)		(2)
Net equipment	—		—
Investments in subsidiaries	30,232		25,244
Other investments	181		186
Operating lease right of use asset	—		3
Deferred income taxes	297		237
Total noncurrent assets	30,710		25,670
Total Assets	$	30,879	$	25,966
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt, classified as current	27		28
Accounts payable – other	200		49
Operating lease liabilities	—		3
Other current liabilities	69		72
Total current liabilities	296		152
Noncurrent Liabilities
Debtor-in-possession financing	4,592		4,624
Operating lease liabilities	—		—
Other noncurrent liabilities	168		191
Total noncurrent liabilities	4,760		4,815
Common Shareholders’ Equity
Common stock	35,129		30,224
Reinvested earnings	(9,286)		(9,198)
Accumulated other comprehensive loss	(20)		(27)
Total common shareholders’ equity	25,823		20,999
Total Liabilities and Shareholders’ Equity	$	30,879	$	25,966

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

	Year ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities:
Net loss	$	(88)	$	(1,304)	$	(7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	51		28		43
Equity in earnings (loss) of subsidiaries	(139)		(412)		7,622
Deferred income taxes and tax credits-net	(60)		(50)		—
Reorganization items, net (Note 2)	(32)		1,548		11
Current income taxes receivable/payable	2		—		6
Liabilities subject to compromise	—		12		28
Other	81		97		(62)
Net cash provided by (used in) operating activities	(185)		(81)		6
Cash Flows From Investing Activities:
Investment in subsidiaries	—		(12,986)		—
Net cash used in investing activities	—		(12,986)		—
Cash Flows From Financing Activities:
Debtor-in-possession credit facility debt issuance costs	—		—		(16)
Bridge facility financing fees	—		(40)		—
Proceeds from issuance of long-term debt	—		4,660		—
Repayment of long-term debt	(28)		(664)		—
Intercompany note from the Utility	145		—		—
Common stock issued	—		7,582		85
Equity Units issued	—		1,304		—
Other	(29)		—		—
Net cash provided by financing activities	88		12,842		69
Net change in cash and cash equivalents	(97)		(225)		75
Cash and cash equivalents at January 1	223		448		373
Cash and cash equivalents at December 31	$	126	$	223	$	448
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(207)	$	(105)	$	(3)
Income taxes, net	1		—		—
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets	$	—	$	—	$	9
Common stock issued in satisfaction of liabilities	—		8,276		—
Increase to PG&E Corporation common stock and treasury stock in connection     with the Share Exchange and Tax Matters Agreement	4,854		—		—

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SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2021

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2021, 2020, and 2019

(in millions)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146
2019:
Allowance for uncollectible accounts (1)	$	56	$	—	$	—	$	13	$	43

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2021, 2020, and 2019

(in millions)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146
2019:
Allowance for uncollectible accounts (1)	$	56	$	—	$	—	$	13	$	43

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Basis of Presentation

This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 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 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 Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.

Use of Estimates and Assumptions

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the 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.

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, 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.  These differences have no impact on net income.  See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  As of December 31, 2020, the Utility also held restricted cash that primarily consisted of cash held in escrow to be used to pay bankruptcy related professional fees.

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 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 GRCs, which occur every 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 Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility 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.

Allowance for Doubtful Accounts Receivable and Credit Losses

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2021, PG&E Corporation and the Utility have identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates.

As of December 31, 2021, the allowance also included the estimated impact of the CAPP which offers financial assistance from the State of California for eligible customers in the form of a credit to the customer’s bill. The Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received on January 27, 2022.

As of December 31, 2021, the Utility recorded $209 million of long-term accounts receivables as a result of the CPUC’s June 30, 2021 final decision on bill debt relief which offers financial assistance for eligible customers in the form of a 24-month payment plan.

As of December 31, 2021, expected credit losses of $154 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. At December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

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. Wildfire fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 14 below. Wildfire fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of the claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for its available-for-sale debt securities. An impairment may exist if there is an intent to sell or a requirement to sell before recovery of the amortized basis. If such an impairment exists, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of December 31, 2021, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, And Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  See “AFUDC” below. The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.82% in 2021, 3.76% in 2020, and 3.80% in 2019.  The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.

Nuclear Decommissioning Obligation

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding.  In December 2021, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly decreased its ARO liabilities by $1.4 billion. The adjustment was a result of a decrease in estimated costs based on refinements to the site-specific decommissioning analysis. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

Disallowance of Plant Costs

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

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC. 

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.

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.  

Consolidated VIEs

Receivables Securitization Program

The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5 below) in October 2020 is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells 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, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets. As of December 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021 and 2020, the SPV had net accounts receivable of $3.3 billion and $2.6 billion, respectively, and outstanding borrowings of $974 million and $1.0 billion, respectively, under the Receivables Securitization Program.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Financing Order for AB 1054, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The recovery bonds are scheduled to pay principal and interest semi-annually on January 15 and July 15 of each year. The final scheduled payment date is July 15, 2046. Amounts owed to bond-holders are included in Long-term debt and Long-term debt, classified as current, on the Consolidated Balance Sheets.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021, PG&E Recovery Funding LLC has outstanding borrowings of $860 million.

Non-Consolidated VIEs

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 was the primary beneficiary of any of these VIEs at December 31, 2021, it 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 December 31, 2021, it did not consolidate any of them.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

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

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets.

Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted

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 adopted this ASU on January 1, 2021. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Government Assistance

In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance, which increases the transparency of government assistance including the disclosure of (1) the types of assistance, (2) an entity’s accounting for the assistance, and (3) the effect of the assistance on an entity’s financial statements. PG&E Corporation and the Utility adopted this ASU as of December 31, 2021. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

DebtIn 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 became effective for PG&E Corporation and the Utility on January 1, 2022 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.

Earnings Per Share

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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.

Fair Value Measurement

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

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

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

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

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

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BANKRUPTCY FILING (Tables)

12 Months Ended

Dec. 31, 2021

Reorganizations [Abstract]

Schedule of Debtor Reorganization Items

Reorganization items, net for the year ended December 31, 2021 include the following:

	Year Ended December 31, 2021
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	21		(1)		20
Interest and other	(9)		—		(9)
Total reorganization items, net	$	12	$	(1)	$	11

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

Reorganization items, net for the year ended December 31, 2020 include the following:

	Year Ended December 31, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	6	$	—	$	6
Legal and other (2)	318		1,651		1,969
Interest income	(14)		(2)		(16)
Total reorganization items, net	$	310	$	1,649	$	1,959

(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 from the Petition Date through December 31, 2019 include the following:

	Petition Date Through December 31, 2019
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	273		19		292
Interest income	(50)		(10)		(60)
Total reorganization items, net	$	320	$	26	$	346

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Revenues Disaggregated by Type of Customer

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

	Year Ended
(in millions)	2021		2020
Electric
Revenue from contracts with customers
Residential	$	6,089	$	5,523
Commercial	5,042		4,722
Industrial	1,493		1,530
Agricultural	1,565		1,471
Public street and highway lighting	73		69
Other (1)	(84)		(130)
Total revenue from contracts with customers - electric	14,178		13,185
Regulatory balancing accounts (2)	953		673
Total electric operating revenue	$	15,131	$	13,858
Natural gas
Revenue from contracts with customers
Residential	$	2,759	$	2,517
Commercial	713		597
Transportation service only	1,346		1,211
Other (1)	140		61
Total revenue from contracts with customers - gas	4,958		4,386
Regulatory balancing accounts (2)	553		225
Total natural gas operating revenue	5,511		4,611
Total operating revenues	$	20,642	$	18,469

(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.

Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment

The Utility’s estimated service lives of its property, plant, and equipment were as follows:

	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2021		2020
Electricity generating facilities (1)	5 to 75	$	11,217	$	12,505
Electricity distribution facilities	10 to 70	37,723		34,902
Electricity transmission facilities	15 to 75	15,516		14,414
Natural gas distribution facilities	20 to 60	14,100		12,962
Natural gas transmission and storage facilities	5 to 66	9,067		8,293
Financing lease		18		18
Construction work in progress		3,480		2,757
General plant and other	5 to 50	7,838		8,041
Total property, plant, and equipment		98,959		93,892
Accumulated depreciation		(29,131)		(27,756)
Net property, plant, and equipment (2)		$	69,828	$	66,136

(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below.

(2) Includes $850 million of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below.

Schedule of Changes in Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2021 and 2020, including nuclear decommissioning obligations:

(in millions)	2021		2020
ARO liability at beginning of year	$	6,412	$	5,854
Liabilities incurred in the current period	—		268
Revision in estimated cash flows	(1,378)		53
Accretion	287		265
Liabilities settled	(23)		(28)
ARO liability at end of year	$	5,298	$	6,412

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2021 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(39)	$	17	$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)	1,007		137		1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)	(1,003)		(136)		(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively) (1)	4		(24)		(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)	2		14		16
Net current period other comprehensive income	6		1		7
Ending balance	$	(33)	$	18	$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details. 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:

(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(22)	$	17	$	(5)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively)	(417)		170		(247)
Regulatory account transfer (net of taxes of $155 and $66, respectively)	400		(170)		230
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)	(4)		10		6
Amortization of net actuarial (gain) loss (net of taxes of $1 and $6, respectively)(1)	2		(15)		(13)
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1)	2		5		7
Net current period other comprehensive loss	(17)		—		(17)
Ending balance	$	(39)	$	17	$	(22)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.

Schedule of Lease Expense

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

	Year Ended December 31,
(in millions)	2021		2020
Operating lease fixed cost	$	578	$	679
Operating lease variable cost	1,782		1,852
Total operating lease costs	$	2,360	$	2,531

Schedule of Future Expected Operating Lease Payments

At December 31, 2021, the Utility’s future expected operating lease payments were as follows:

(in millions)	December 31, 2021
2022	$	533
2023	276
2024	118
2025	111
2026	105
Thereafter	444
Total lease payments	1,587
Less imputed interest	(310)
Total	$	1,277

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at December 31,				Recovery Period
(in millions)	2021		2020
Pension benefits (1)	$	708	$	2,245	Indefinitely
Environmental compliance costs	1,089		1,112		32 years
Utility retained generation (2)	133		181		6 years
Price risk management	216		204		19 years
Unamortized loss, net of gain, on reacquired debt	37		49		23 years
Catastrophic event memorandum account (3)	1,119		842		1 - 3 years
Wildfire expense memorandum account (4)	347		400		TBD years
Fire hazard prevention memorandum account (5)	75		137		1 - 3 years
Fire risk mitigation memorandum account (6)	44		66		1 - 3 years
Wildfire mitigation plan memorandum account (7)	424		390		1 - 3 years
Deferred income taxes (8)	1,849		908		51 years
Insurance premium costs (9)	207		294		3 - 4 years
Wildfire mitigation balancing account (10)	273		156		1 - 3 years
General rate case memorandum accounts (11)	—		376		1 - 2 years
Vegetation management balancing account (12)	1,411		592		1 - 3 years
COVID-19 pandemic protection memorandum accounts (13)	49		84		TBD years
Other	1,226		942		Various
Total long-term regulatory assets	$	9,207	$	8,978

(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 December 31, 2021 and 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Balance as of December 31, 2021 represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire. Balance as of December 31, 2020 is comprised of incremental wildfire liability insurance premium costs for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is 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 is subject to CPUC review and approval.

(6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through December 31, 2021. Recovery of WMPMA costs is 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 excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2021. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) The GRC memorandum accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered through rates over 22 months, beginning March 1, 2021.

(12) Represents costs from routine vegetation management and EVM activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA for the period January 1, 2020 through December 31, 2021. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.

(13) On April 16, 2020, the CPUC passed a resolution that established the 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 certain residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2021, the Utility had recorded an under-collection of $30 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA was in effect. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at December 31,
(in millions)	2021		2020
Cost of removal obligations (1)	$	7,306	$	6,905
Recoveries in excess of AROs (2)	388		458
Public purpose programs (3)	946		948
Employee benefit plans (4)	1,229		995
Transmission tower wireless licenses (5)	446		—
SFGO sale (6)	343		—
Other	1,341		1,118
Total long-term regulatory liabilities	$	11,999	$	10,424

(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 11 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.

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $446 million, $311 million and $135 million will be refunded to FERC and CPUC jurisdiction customers, respectively. See Note 3 above.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period, beginning in 2022.

Current Regulatory Balancing Accounts Receivable

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

	Receivable Balance at December 31,
(in millions)	2021		2020
Gas distribution and transmission	$	—	$	102
Energy procurement	310		413
Public purpose programs	321		292
Fire hazard prevention memorandum account	50		121
Fire risk mitigation memorandum account	14		33
Wildfire mitigation plan memorandum account	67		161
Wildfire mitigation balancing account	91		27
General rate case memorandum accounts	468		313
Vegetation management balancing account	127		115
Insurance premium costs	605		135
Wildfire expense memorandum account	440		—
Residential uncollectibles balancing accounts	127		—
Other	379		289
Total regulatory balancing accounts receivable	$	2,999	$	2,001

Current Regulatory Balancing Accounts Payable

	Payable Balance at December 31,
(in millions)	2021		2020
Electric distribution	$	121	$	55
Electric transmission	24		267
Gas distribution and transmission	83		76
Energy procurement	211		158
Public purpose programs	259		410
Nuclear decommissioning adjustment mechanism	137		—
Other	286		279
Total regulatory balancing accounts payable	$	1,121	$	1,245

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DEBT (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Line of Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2021:

(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding			Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2026	$	4,000	(1)	$	1,885		$	692	$	1,423
Utility term loan credit facility	October 2022 (2)	1,441		(2)	1,441		(2)	—		—
Utility receivables securitization program (3)	September 2023	1,000		(4)	974			—		—		(4)
PG&E Corporation revolving credit facility	June 2024	500			—			—		500
Total credit facilities		$	6,941		$	4,300		$	692	$	1,923

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

(2 On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022.

(3) On October 5, 2020, the Utility 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 the SPV, a limited liability company wholly owned by the Utility. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023. For more information, see “Variable Interest Entities” in Note 3 above.

(4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program. As of December 31, 2021, the Receivables Securitization Program had a maximum borrowing base of $974 million and was fully drawn.

Schedule of Long-term Debt

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

		Balance at
(in millions)	Contractual Interest Rates	December 31, 2021		December 31, 2020
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,709	$	2,709
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of debt issuance costs		(26)		—
Unamortized discount, net of premium and debt issuance costs		(90)		(85)
Total PG&E Corporation Long-Term Debt		4,593		4,624
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	500		500
2022	1.75%	2,500		2,500
2023	1.37% - 4.25%	3,575		1,175
2024	3.40% - 3.75%	800		800
2025	3.45% - 3.50%	1,475		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 3.30%	2,550		2,550
2028	3.00% - 4.65%	1,975		1,175
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		2,000
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		250
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
Less: current portion, net of debt issuance costs		(2,996)		—
Unamortized discount, net of premium and debt issuance costs		(190)		(182)
Total Utility First Mortgage Bonds		31,816		30,170
Recovery Bonds	1.46% - 2.82%	860		—
Less: current portion		(18)		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2023	variable rate (3)	974		1,000
18-month Term Loan - Stated Maturity: 2022	variable rate (4)	1,441		1,500
Less: current portion		(1,441)		—
Unamortized discount, net of premium and debt issuance costs		—		(6)
Total Utility Long-Term Debt		33,632		32,664
Total PG&E Corporation Consolidated Long-Term Debt		$	38,225	$	37,288

(1) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 3.50% and 5.50%, respectively.

(2) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69% and 1.70%, respectively.

(3) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.30% and 1.57%, respectively.

(4) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 2.38% and 2.44%, respectively.

Schedule of Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2021 are reflected in the table below:

(in millions, except interest rates)	2022			2023			2024			2025			2026			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	—		%	—		%	5.13		%	5.13		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	2,000		$	2,000
Variable interest rate as of December 31, 2021	3.50		%	3.50		%	3.50		%	3.50		%	—		%	—		%	3.50		%
Variable rate obligations	$	28		$	28		$	28		$	2,625		$	—		$	—		$	2,709
Utility
Average fixed interest rate	1.75		%	2.26		%	3.60		%	3.47		%	3.10		%	3.90		%	3.49		%
Fixed rate obligations	$	2,500		$	3,575		$	800		$	1,475		$	2,551		$	23,601		$	34,502
Variable interest rate as of December 31, 2021	2.20		%	various (1)			—		%	—		%	—		%	—		%	various (1)
Variable rate obligations	$	1,941		$	974		$	—		$	—		$	—		$	—		$	2,915
Total consolidated debt	$	4,469		$	4,577		$	828		$	4,100		$	2,551		$	25,601		$	42,126

(1) At December 31, 2021, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.30%, 1.69% and 2.38% respectively.

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COMMON STOCK AND SHARE-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2021

Common Stock And Share-Based Compensation [Abstract]

Schedule of Compensation Expense for Share-based Incentive Awards

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2021:

(in millions)	2021		2020		2019
Stock Options	$	—	$	3	$	7
Restricted stock units	35		15		21
Performance shares	21		17		22
Total compensation expense (pre-tax)	$	56	$	35	$	50
Total compensation expense (after-tax)	$	40	$	25	$	35

Summary of Stock Option Activity

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2021:

	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,221,247	$	7.45		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(25,413)	10.23			—
Outstanding at December 31	2,195,834	7.42		4.33	—
Vested or expected to vest at December 31	2,195,834	7.42		4.33	—
Exercisable at December 31	2,195,834	$	7.42	4.33	$	—

(1) Represents additional payout of existing stock option grants.

Schedule of Restricted Stock Units

The following table summarizes restricted stock unit activity for 2021:

	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	890,353	$	23.05
Granted	10,352,117	11.01
Vested	(743,672)	25.20
Forfeited	(408,423)	11.67
Nonvested at December 31	10,090,375	$	11.00

Schedule of Performance Shares

The following table summarizes activity for performance shares in 2021:

	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	7,288,782	$	9.16
Granted	2,714,645	11.83
Vested	—	—
Forfeited (1)	(1,436,418)	11.35
Nonvested at December 31	8,567,009	$	9.64

(1) Includes performance shares that expired with zero value as performance targets were not met.

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Earnings Per Share

The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2021, 2020, and 2019.

	Year Ended December 31,
(in millions, except per share amounts)	2021		2020		2019
Loss attributable to common shareholders	$	(102)	$	(1,318)	$	(7,656)
Weighted average common shares outstanding, basic	1,985		1,257		528
Add incremental shares from assumed conversions:
Employee share-based compensation	—		—		—
Equity Units	—		—		—
Weighted average common share outstanding, diluted	1,985		1,257		528
Total Loss per common share, diluted	$	(0.05)	$	(1.05)	$	(14.50)

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2021		2020		2019		2021		2020		2019
Current:
Federal	$	—	$	(26)	$	1	$	—	$	(26)	$	4
State	1		(34)		101		—		(34)		94
Deferred:
Federal	543		258		(2,361)		588		290		(2,363)
State	296		171		(1,136)		316		185		(1,137)
Tax credits	(4)		(7)		(5)		(4)		(7)		(5)
Income tax provision (benefit)	$	836	$	362	$	(3,400)	$	900	$	408	$	(3,407)

Schedule of Deferred Tax Assets and Liabilities

The following tables describe net deferred income tax assets and liabilities:

	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2021		2020		2021		2020
Deferred income tax assets:
Tax carryforwards	$	5,628	$	7,641	$	5,425	$	7,529
Compensation	185		187		108		109
Wildfire-related claims (1)	1,723		544		1,723		544
Operating lease liability	346		489		346		488
Transmission tower wireless licenses	266		—		266		—
Other (2)	278		212		293		219
Total deferred income tax assets	$	8,426	$	9,073	$	8,161	$	8,889
Deferred income tax liabilities:
Property related basis differences	8,847		8,311		8,835		8,300
Regulatory balancing accounts	1,193		763		1,193		763
Debt financing costs	501		526		501		526
Operating lease right of use asset	346		489		346		488
Income tax regulatory asset (3)	517		254		517		254
Other (4)	199		128		178		128
Total deferred income tax liabilities	$	11,603	$	10,471	$	11,570	$	10,459
Total net deferred income tax liabilities	$	3,177	$	1,398	$	3,409	$	1,570

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service territory over the past several years.

(2) Amounts include benefits, environmental reserve, and customer advances for construction. 

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.

(4) Amount primarily includes an environmental reserve.

Schedule of Effective Income Tax Rate Reconciliation

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

	PG&E Corporation						Utility
	Year Ended December 31,
	2021		2020		2019		2021		2020		2019
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	31.3		(15.3)		7.5		24.1		19.1		7.5
Effect of regulatory treatment of fixed asset differences (2)	(71.5)		39.0		2.8		(51.6)		(44.9)		2.8
Tax credits	(1.7)		1.5		0.1		(1.2)		(1.7)		0.1
Fire Victim Trust (3)	127.3		(44.9)		—		91.9		51.7		—
Bankruptcy and emergence	—		(37.6)		—		—		2.4		—
Other, net (4)	5.3		(2.1)		(0.6)		2.6		2.2		(0.5)
Effective tax rate	111.7	%	(38.4)	%	30.8	%	86.8	%	49.8	%	30.9	%

(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 2021, 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) The Utility includes an adjustment for a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for 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 in 2020. PG&E Corporation includes the same adjustment as the Utility in 2021 and 2020 as well as a permanent non-deductible equity backstop premium expense in 2020. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively in 2020, accounts for the remaining difference.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs in 2021 and 2020.

Schedule of Change in Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:

	PG&E Corporation						Utility
(in millions)	2021		2020		2019		2021		2020		2019
Balance at beginning of year	$	437	$	420	$	377	$	437	$	420	$	377
Reductions for tax position taken during a prior year	(23)		(43)		(1)		(23)		(43)		(1)
Additions for tax position taken during the current year	85		60		44		85		60		44
Settlements	(1)		—		—		(1)		—		—
Balance at end of year	$	498	$	437	$	420	$	498	$	437	$	420

Schedule of Operating Loss and Tax Credit Carryforward Balances

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

(in millions)	December 31, 2021		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,600	2031 - 2036
Net operating loss carryforward - Post-2017	17,467		N/A
Tax credit carryforward	144		2029 - 2041
State:
Net operating loss carryforward	$	18,853	2039 - 2041
Tax credit carryforward	122		Various

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Volumes of Outstanding Derivative Contracts

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

		Contract Volume
		At December 31,
Underlying Product	Instruments	2021	2020
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	173,361,635	146,642,863
	Options	14,420,000	14,140,000
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	10,283,639	9,435,830
	Options	288,000	—
	Congestion Revenue Rights (3)	239,857,610	266,091,470

(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.

Outstanding Derivative Balances

At December 31, 2021, 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	$	58	$	(9)	$	152	$	201
Other noncurrent assets – other	169		—		—		169
Current liabilities – other	(53)		9		18		(26)
Noncurrent liabilities – other	(216)		—		—		(216)
Total commodity risk	$	(42)	$	—	$	170	$	128

At December 31, 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	$	33	$	—	$	115	$	148
Other noncurrent assets – other	136		—		—		136
Current liabilities – other	(38)		—		15		(23)
Noncurrent liabilities – other	(204)		—		10		(194)
Total commodity risk	$	(73)	$	—	$	140	$	67

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

	Fair Value Measurements
	At December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	289	$	—	$	—	$	—	$	289
Nuclear decommissioning trusts
Short-term investments	22		—		—		—		22
Global equity securities	2,504		—		—		—		2,504
Fixed-income securities	1,158		866		—		—		2,024
Assets measured at NAV	—		—		—		—		31
Total nuclear decommissioning trusts (2)	3,684		866		—		—		4,581
Price risk management instruments (Note 10)
Electricity	—		9		214		6		229
Gas	—		4		—		137		141
Total price risk management instruments	—		13		214		143		370
Rabbi trusts
Fixed-income securities	—		104		—		—		104
Life insurance contracts	—		76		—		—		76
Total rabbi trusts	—		180		—		—		180
Long-term disability trust
Short-term investments	6		—		—		—		6
Assets measured at NAV	—		—		—		—		132
Total long-term disability trust	6		—		—		—		138
TOTAL ASSETS	$	3,979	$	1,059	$	214	$	143	$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	11	$	248	$	(24)	$	235
Gas	—		10		—		(3)		7
TOTAL LIABILITIES	$	—	$	21	$	248	$	(27)	$	242

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

(2) Represents amount before deducting $783 million, primarily related to deferred taxes on appreciation of investment value. 

	Fair Value Measurements
	At December 31, 2020
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	470	$	—	$	—	$	—	$	470
Nuclear decommissioning trusts
Short-term investments	27		—		—		—		27
Global equity securities	2,398		—		—		—		2,398
Fixed-income securities	924		835		—		—		1,759
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,349		835		—		—		4,209
Price risk management instruments (Note 10)
Electricity	—		2		166		2		170
Gas	—		1		—		113		114
Total price risk management instruments	—		3		166		115		284
Rabbi trusts
Fixed-income securities	—		106		—		—		106
Life insurance contracts	—		79		—		—		79
Total rabbi trusts	—		185		—		—		185
Long-term disability trust
Short-term investments	9		—		—		—		9
Assets measured at NAV	—		—		—		—		158
Total long-term disability trust	9		—		—		—		167
TOTAL ASSETS	$	3,828	$	1,023	$	166	$	115	$	5,315
Liabilities:
Price risk management instruments (Note 10)
Electricity	—		1		238		(25)		214
Gas	—		3		—		—		3
TOTAL LIABILITIES	$	—	$	4	$	238	$	(25)	$	217

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

(2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value.

Uncertainty Analysis

	Fair Value at
(in millions)	At December 31, 2021				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	188	$	93	Market approach	CRR auction prices	$ (40.77) - 2,265.94 / 0.40
Power purchase agreements	$	26	$	155	Discounted cash flow	Forward prices	$ (7.97) - 256.20 / 47.17

(1) Represents price per megawatt-hour.

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

	Fair Value at
(in millions)	At December 31, 2020				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities				Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	153	$	74	Market approach	CRR auction prices	$ (320.25) - 320.25 / 0.30
Power purchase agreements	$	13	$	164	Discounted cash flow	Forward prices	$ 12.56 - 148.30 / 35.52

(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 price risk management instruments for the years ended December 31, 2021 and 2020, respectively:

	Price Risk Management Instruments
(in millions)	2021		2020
Asset (liability) balance as of January 1	$	(72)	$	5
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	38		(77)
Asset (liability) balance as of December 31	$	(34)	$	(72)

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

Carrying Amount and Fair Value of Financial Instruments

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

	At December 31,
	2021				2020
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,619	$	4,796	$	1,901	$	2,175
Utility	31,816		35,803		29,664		32,632

Schedule of Unrealized Gains (Losses) Related to Available-for-sale Investments

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

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments	$	22	$	—	$	—	$	22
Global equity securities	479		2,066		(10)		2,535
Fixed-income securities	1,938		98		(12)		2,024
Total (1)	$	2,439	$	2,164	$	(22)	$	4,581
As of December 31, 2020
Nuclear decommissioning trusts
Short-term investments	$	27	$	—	$	—	$	27
Global equity securities	543		1,881		(1)		2,423
Fixed-income securities	1,610		152		(3)		1,759
Total (1)	$	2,180	$	2,033	$	(4)	$	4,209

(1) Represents amounts before deducting $783 million and $671 million at December 31, 2021 and 2020, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule of Long Term Debt Repayments

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

	As of
(in millions)	December 31, 2021
Less than 1 year	$	97
1–5 years	495
5–10 years	480
More than 10 years	952
Total maturities of fixed-income securities	$	2,024

Schedule of Activity for Debt and Equity Securities

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

(in millions)	2021		2020		2019
Proceeds from sales and maturities of nuclear decommissioning investments	$	1,678	$	1,518	$	956
Gross realized gains on securities	286		159		69
Gross realized losses on securities	(19)		(41)		(14)

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2021

Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract]

Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2021 and 2020:

Pension Plan

(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	20,759	$	18,547
Actual return on plan assets	1,693		2,736
Company contributions	335		343
Benefits and expenses paid	(892)		(867)
Fair value of plan assets at end of year	$	21,895	$	20,759
Change in benefit obligation:
Benefit obligation at beginning of year	$	23,172	$	20,525
Service cost for benefits earned	587		530
Interest cost	645		713
Actuarial (gain) loss (1)	(752)		2,271
Plan amendments	—		—
Benefits and expenses paid	(893)		(867)
Benefit obligation at end of year (2)	$	22,759	$	23,172
Funded Status:
Current liability	$	(9)	$	(3)
Noncurrent liability	(856)		(2,410)
Net liability at end of year	$	(865)	$	(2,413)

(1) The actuarial gain for the year ended December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions. The actuarial loss for the year ended December 31, 2020 was due to a decrease in the discount rate used to measure the projected benefit obligation.

(2) PG&E Corporation’s accumulated benefit obligation was $20.4 billion and $20.7 billion at December 31, 2021 and 2020, respectively.

Postretirement Benefits Other than Pensions

(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,995	$	2,678
Actual return on plan assets	193		379
Company contributions	10		26
Plan participant contribution	80		81
Benefits and expenses paid	(176)		(169)
Fair value of plan assets at end of year	$	3,102	$	2,995
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,876	$	1,832
Service cost for benefits earned	63		61
Interest cost	51		63
Actuarial gain (1)	(152)		(14)
Benefits and expenses paid	(156)		(149)
Federal subsidy on benefits paid	4		3
Plan participant contributions	80		80
Benefit obligation at end of year	$	1,766	$	1,876
Funded Status: (2)
Noncurrent asset	$	1,340	$	1,153
Noncurrent liability	(4)		(34)
Net asset at end of year	$	1,336	$	1,119

(1) The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes. The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation.

(2) At December 31, 2021 and 2020, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $363 million and $359 million as of December 31, 2021, and $377 million and $343 million as of December 31, 2020, respectively.

Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan

(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	587	$	530	$	443
Interest cost	645		713		758
Expected return on plan assets	(1,046)		(1,044)		(906)
Amortization of prior service cost	(6)		(6)		(6)
Amortization of net actuarial loss	6		3		3
Net periodic benefit cost	186		196		292
Less: transfer to regulatory account (2)	147		136		42
Total expense recognized	$	333	$	332	$	334

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

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions

(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	63	$	61	$	56
Interest cost	51		63		76
Expected return on plan assets	(137)		(138)		(123)
Amortization of prior service cost	14		14		14
Amortization of net actuarial loss	(33)		(21)		(3)
Net periodic benefit cost	$	(42)	$	(21)	$	20

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

Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.

	Pension Plan						PBOP Plans
	December 31,						December 31,
	2021		2020		2019		2021	2020	2019
Discount rate	3.03	%	2.77	%	3.46	%	2.97 - 3.04%	2.67 - 2.80 %	3.37 - 3.47%
Rate of future compensation increases	3.80	%	3.80	%	3.90	%	N/A	N/A	N/A
Expected return on plan assets	5.50	%	5.10	%	5.70	%	3.30 - 6.40%	3.10 - 6.10 %	3.50 - 6.60%
Interest crediting rate for cash balance plan	1.95	%	1.95	%	2.11	%	N/A	N/A	N/A

Target Asset Allocation Percentages

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

	Pension Plan						PBOP Plans
	2022		2021		2020		2022		2021		2020
Global equity securities	30	%	30	%	30	%	26	%	36	%	28	%
Absolute return	2	%	2	%	2	%	1	%	1	%	2	%
Real assets	8	%	8	%	8	%	3	%	5	%	8	%
Fixed-income securities	60	%	60	%	60	%	70	%	58	%	62	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Schedule of Changes in Fair Value of Plan Assets

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2021 and 2020. 

	Fair Value Measurements
	At December 31,
	2021								2020
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	552	$	255	$	—	$	807	$	334	$	408	$	—	$	742
Global equity securities	2,074		424		—		2,498		1,875		—		—		1,875
Absolute Return	—		1		—		1		1		1		—		2
Real assets	632		—		—		632		517		—		—		517
Fixed-income securities	2,729		7,388		27		10,144		2,467		7,154		12		9,633
Assets measured at NAV	—		—		—		7,972		—		—		—		8,224
Total	$	5,987	$	8,068	$	27	$	22,054	$	5,194	$	7,563	$	12	$	20,993
PBOP Plans:
Short-term investments	$	31	$	—	$	—	$	31	$	37	$	—	$	—	$	37
Global equity securities	105		—		—		105		173		—		—		173
Real assets	34		—		—		34		54		—		—		54
Fixed-income securities	776		875		1		1,652		481		715		1		1,197
Assets measured at NAV	—		—		—		1,296		—		—		—		1,549
Total	$	946	$	875	$	1	$	3,118	$	745	$	715	$	1	$	3,010
Total plan assets at fair value							$	25,172							$	24,003

Schedule of Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2021 and 2020:

(in millions)
For the year ended December 31, 2021	Fixed-Income
Balance at beginning of year	$	12
Actual return on plan assets:
Relating to assets still held at the reporting date	6
Relating to assets sold during the period	(7)
Purchases, issuances, sales, and settlements:
Purchases	22
Settlements	(6)
Balance at end of year	$	27
(in millions)
For the year ended December 31, 2020	Fixed-Income
Balance at beginning of year	$	15
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(3)
Purchases, issuances, sales, and settlements:
Purchases	11
Settlements	(13)
Balance at end of year	$	12

Schedule of Estimated Benefits Expected to be Paid

As of December 31, 2021, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2022	869	81	(3)
2023	954	85	(3)
2024	988	89	(3)
2025	1018	88	(3)
2026	1,046	91	(3)
Thereafter in the succeeding five years	5,533	466	(3)

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Schedule of Significant Related Party Transactions

The Utility’s significant related party transactions were:

	Year Ended December 31,
(in millions)	2021		2020		2019
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	4
Utility expenses from:
Administrative services received from PG&E Corporation	$	82	$	108	$	107
Utility employee benefit due to PG&E Corporation	39		34		42

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WILDFIRE-RELATED CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Summary of Wildfire-Related Claims

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	625
Payments	—
Balance at December 31, 2020	625
Accrued Losses	175
Payments	(31)
Balance at December 31, 2021	$	769

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2019.

Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	275
Payments	—
Balance at December 31, 2020	275
Accrued Losses	100
Payments	(164)
Balance at December 31, 2021	$	211

Total probable recoveries for the 2021 Dixie fire as of December 31, 2021 are:

Potential Recovery Source (in millions)	2021 Dixie fire
Insurance	$	563
FERC TO rates	101
WEMA	347
Wildfire Fund	150
Probable recoveries at December 31, 2021	$	1,161

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

Insurance Receivable (in millions)	2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	—	$	—	$	1,380	$	808	$	50	$	2,238
Accrued insurance recoveries	—		219		430		—		—		—		649
Reimbursements	—		—		—		(1,380)		(783)		(50)		(2,213)
Balance at December 31, 2020	—		219		430		—		25		—		674
Accrued insurance recoveries (1)	563		118		—		—		—		—		681
Reimbursements (2)	—		(67)		(16)		—		(25)		—		(108)
Balance at December 31, 2021	$	563	$	270	$	414	$	—	$	—	$	—	$	1,247

(1) During the fourth quarter of 2021, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase for the 2020 Zogg fire for $6.5 million.

(2) On January 26, 2022, the Utility received $43 million of insurance reimbursements related to the 2020 Zogg fire.

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OTHER CONTINGENCIES AND COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Schedule of Expense and Capital Expenditures

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 recorded $1.625 billion of the disallowed costs for the year ended December 31, 2020.

(in millions)
Description (1)	Expense		Capital		Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)	$	236	$	—	$	236
Transmission Safety Inspections and Repairs Expense (TO) (2)	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)	—		84		84
Total	$	1,222	$	403	$	1,625

(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.

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

Schedule of Environmental Remediation Liability

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

	Balance at
(in millions)	December 31, 2021		December 31, 2020
Topock natural gas compressor station	$	299	$	303
Hinkley natural gas compressor station	123		132
Former MGP sites owned by the Utility or third parties (1)	667		659
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites (2)	104		111
Fossil fuel-fired generation facilities and sites (3)	70		96
Total environmental remediation liability	$	1,263	$	1,301

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

Schedule of Undiscounted Future Expected Power Purchase Agreement Payments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2021:

	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2022	$	2,062	$	530	$	61	$	823	$	42	$	3,518
2023	2,043		425		61		191		41		2,761
2024	2,020		282		61		157		27		2,547
2025	2,009		216		61		157		—		2,443
2026	1,948		204		21		140		—		2,313
Thereafter	19,310		539		19		52		—		19,920
Total purchase commitments	$	29,392	$	2,196	$	284	$	1,520	$	110	$	33,502

Schedule of Other Commitments

At December 31, 2021, the future minimum payments related to these commitments were as follows:

(in millions)	Other Commitments
2022	$	43
2023	65
2024	81
2025	77
2026	74
Thereafter	2,938
Total minimum lease payments	$	3,278

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ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2021 numberOfSegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

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BANKRUPTCY FILING (Chapter 11 Claims Process) (Details) notice in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) notice
Debt Instrument [Line Items]
Proofs of claims | notice		100
Claims expected to be received	$ 145
Disputed claims and customer refunds	0	$ 242
Current regulatory liabilities expected to be refunded	422
Pacific Gas & Electric Co (Utility)
Debt Instrument [Line Items]
Disputed claims and customer refunds	0	242
Payments for reorganization items	53	400
PG&E Corporation
Debt Instrument [Line Items]
Payments for reorganization items	$ 31	$ 102
Subrogation Wildfire Trust and Fire Victim Trust
Debt Instrument [Line Items]
Proofs of claims | notice		80

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BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reorganizations [Line Items]
Debtor-in-possession financing costs	$ 0	$ 6	$ 114
Legal and other	20	1,969	292
Interest and other	(9)	(16)	(60)
Total reorganization items, net	11	1,959	346
Equity backstop premium expense and bridge loan facility fees
Reorganizations [Line Items]
Legal and other		1,500
PG&E Corporation
Reorganizations [Line Items]
Payments for reorganization items	31	102
Debtor-in-possession financing costs	0	0	17
Legal and other	(1)	1,651	19
Interest and other	0	(2)	(10)
Total reorganization items, net	(1)	1,649	26
Pacific Gas & Electric Co (Utility)
Reorganizations [Line Items]
Payments for reorganization items	53	400
Debtor-in-possession financing costs	0	6	97
Legal and other	21	318	273
Interest and other	(9)	(14)	(50)
Total reorganization items, net	$ 12	$ 310	$ 320

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details)			1 Months Ended	3 Months Ended	12 Months Ended
	Aug. 15, 2021 USD ($)	Feb. 16, 2021 USD ($) transmissionTower	Dec. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 USD ($) facility numberOfFatality	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Nov. 12, 2021 USD ($)	Dec. 30, 2020 USD ($)	Jul. 12, 2019 USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Period for probable revenue recovery					24 months
Expected credit losses			$ 154,000,000	$ 154,000,000	$ 154,000,000
Allowance for credit loss decrease				207,000,000
Regulatory balancing accounts			2,999,000,000	2,999,000,000	2,999,000,000	$ 2,001,000,000
Decrease in nuclear decommissioning obligation			1,400,000,000
Expected capitalization, proceeds of bond			10,500,000,000	10,500,000,000	10,500,000,000
Expected capitalization, initial contribution			7,500,000,000	7,500,000,000	7,500,000,000
Expected capitalization, annual contribution			300,000,000	300,000,000	300,000,000
Expected wildfire fund allocation metric, percentage										64.20%
Expected wildfire fund allocation metric, initial contribution										$ 4,800,000,000
Expected wildfire fund allocation metric, annual contributions										$ 193,000,000
Expected wildfire fund allocation metric, annual contributions, second									$ 193,000,000
Litigation liability, current			193,000,000	193,000,000	193,000,000
Wildfire fund asset			461,000,000	461,000,000	461,000,000	464,000,000
Litigation contribution, net			$ 5,300,000,000	$ 5,300,000,000	5,300,000,000
Amortization and accretion					$ 517,000,000	413,000,000	$ 0
Monte carlo simulation, historical data, period					12 years
Amortization period					6 years
Percentage assumption change			10.00%	10.00%	10.00%
Insurance receivable			$ 1,247,000,000	$ 1,247,000,000	$ 1,247,000,000	674,000,000	2,238,000,000
Operating lease, payments					$ 2,400,000,000	$ 2,500,000,000
Weighted average remaining lease term			6 years 14 days	6 years 14 days	6 years 14 days	5 years 8 months 12 days
Weighted average discount rate			6.10%	6.10%	6.10%	6.20%
Proceeds from contract liability	$ 106,000,000
Litigation Settlement, Expense
Public Utility, Property, Plant and Equipment [Line Items]
Accelerated amortization					$ 43,000,000
2021 Dixie fire
Public Utility, Property, Plant and Equipment [Line Items]
Insurance receivable			$ 563,000,000	$ 563,000,000	563,000,000	$ 0	$ 0
CPUC
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory balancing accounts			209,000,000	209,000,000	209,000,000
COVID-19 Pandemic protection memorandum account
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets			30,000,000	30,000,000	30,000,000
Federal Energy Regulatory Commission
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets			12,000,000	12,000,000	12,000,000
Regulatory Balancing Accounts Receivable
Public Utility, Property, Plant and Equipment [Line Items]
Total regulatory balancing accounts			2,999,000,000	2,999,000,000	2,999,000,000	2,001,000,000
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable
Public Utility, Property, Plant and Equipment [Line Items]
Total regulatory balancing accounts			127,000,000	127,000,000	$ 127,000,000	0
Five Year Historical Period
Public Utility, Property, Plant and Equipment [Line Items]
Historical data period					5 years
Average annual statewide claims or settlements			6,500,000,000	6,500,000,000	$ 6,500,000,000
Twelve Year Historical Period
Public Utility, Property, Plant and Equipment [Line Items]
Historical data period					12 years
Average annual statewide claims or settlements			2,900,000,000	2,900,000,000	$ 2,900,000,000
Wildfire Fund Asset
Public Utility, Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life					15 years
Noncurrent liabilities – other
Public Utility, Property, Plant and Equipment [Line Items]
Wildfire fund, noncurrent			1,100,000,000	1,100,000,000	$ 1,100,000,000
Other noncurrent assets – other | 2021 Dixie fire
Public Utility, Property, Plant and Equipment [Line Items]
Insurance receivable			150,000,000	150,000,000	150,000,000
Recovery Bonds | Senior Secured Superpriority Debt
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount			$ 860,000,000	$ 860,000,000	$ 860,000,000	0		$ 860,000,000
Recovery Bonds | Senior Secured Superpriority Debt | Tranche One
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount								$ 266,000,000
Interest rate								1.46%
Recovery Bonds | Senior Secured Superpriority Debt | Tranche Two
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount								$ 160,000,000
Interest rate								2.28%
Recovery Bonds | Senior Secured Superpriority Debt | Tranche Three
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument, face amount								$ 434,000,000
Interest rate								2.82%
Recovery Bonds | Minimum | Senior Secured Superpriority Debt
Public Utility, Property, Plant and Equipment [Line Items]
Interest rate			1.46%	1.46%	1.46%
Pacific Gas & Electric Co (Utility)
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory balancing accounts			$ 2,999,000,000	$ 2,999,000,000	$ 2,999,000,000	$ 2,001,000,000
Composite depreciation rate					3.82%	3.76%	3.80%
AFUDC debt recorded					$ 56,000,000	$ 35,000,000	$ 55,000,000
AFUDC equity recorded					133,000,000	140,000,000	79,000,000
Nuclear decommissioning obligation accrued					3,900,000,000	5,100,000,000
Estimated cost recovery on spent nuclear fuel storage proceeding every year					7,600,000,000	10,600,000,000
Wildfire fund asset			461,000,000	461,000,000	461,000,000	464,000,000
Amortization and accretion					517,000,000	413,000,000	$ 0
Pacific Gas & Electric Co (Utility) | SBA Communications Corporation | Wireless Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Duration of contract		100 years
Other tower, duration of contract		15 years
Proceeds from sale of transmission tower license		$ 946,000,000
Proceeds from sale of transmission tower license, closing	947,000,000
Proceeds from financing obligations	$ 370,000,000
Proceeds from contract liability		471,000,000
Proceeds from regulatory liabilities, noncurrent		$ 455,000,000
Pacific Gas & Electric Co (Utility) | Effective Date Towers | SBA Communications Corporation | Wireless Licenses | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Number of electric transmission towers | transmissionTower		700
Number of other electric transmission towers | transmissionTower		28,000
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program
Public Utility, Property, Plant and Equipment [Line Items]
Aggregate maximum amount of loans made by lenders			1,000,000,000	1,000,000,000	1,000,000,000
Debt financial instrument			974,000,000	974,000,000	974,000,000	1,000,000,000
Long-term debt, gross			974,000,000	974,000,000	$ 974,000,000	1,000,000,000
Pacific Gas & Electric Co (Utility) | Diablo Canyon
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | facility					2
Pacific Gas & Electric Co (Utility) | Humboldt Bay
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | numberOfFatality					1
PG&E AR Facility, LLC (SPV) | Receivables Securitization Program
Public Utility, Property, Plant and Equipment [Line Items]
Accounts receivable, net			$ 3,300,000,000	$ 3,300,000,000	$ 3,300,000,000	$ 2,600,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Abstract]
Total operating revenues	$ 20,642	$ 18,469	$ 17,129
Electric
Disaggregation of Revenue [Abstract]
Total operating revenues	15,131	13,858	12,740
Natural gas
Disaggregation of Revenue [Abstract]
Total operating revenues	5,511	4,611	4,389
Pacific Gas & Electric Co (Utility)
Disaggregation of Revenue [Abstract]
Total operating revenues	20,642	18,469	17,129
Pacific Gas & Electric Co (Utility) | Electric
Disaggregation of Revenue [Abstract]
Total operating revenues	14,178	13,185
Regulatory balancing accounts	953	673
Total operating revenues	15,131	13,858	12,740
Pacific Gas & Electric Co (Utility) | Electric | Residential
Disaggregation of Revenue [Abstract]
Total operating revenues	6,089	5,523
Pacific Gas & Electric Co (Utility) | Electric | Commercial
Disaggregation of Revenue [Abstract]
Total operating revenues	5,042	4,722
Pacific Gas & Electric Co (Utility) | Electric | Industrial
Disaggregation of Revenue [Abstract]
Total operating revenues	1,493	1,530
Pacific Gas & Electric Co (Utility) | Electric | Agricultural
Disaggregation of Revenue [Abstract]
Total operating revenues	1,565	1,471
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting
Disaggregation of Revenue [Abstract]
Total operating revenues	73	69
Pacific Gas & Electric Co (Utility) | Electric | Other
Disaggregation of Revenue [Abstract]
Total operating revenues	(84)	(130)
Pacific Gas & Electric Co (Utility) | Natural gas
Disaggregation of Revenue [Abstract]
Total operating revenues	4,958	4,386
Regulatory balancing accounts	553	225
Total operating revenues	5,511	4,611	$ 4,389
Pacific Gas & Electric Co (Utility) | Natural gas | Residential
Disaggregation of Revenue [Abstract]
Total operating revenues	2,759	2,517
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial
Disaggregation of Revenue [Abstract]
Total operating revenues	713	597
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only
Disaggregation of Revenue [Abstract]
Total operating revenues	1,346	1,211
Pacific Gas & Electric Co (Utility) | Natural gas | Other
Disaggregation of Revenue [Abstract]
Total operating revenues	$ 140	$ 61

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utilities Property, Plant and Equipment) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 98,959	$ 93,892
Accumulated depreciation	(29,131)	(27,756)
Net property, plant, and equipment	69,828	66,136
Electricity generating facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	11,217	12,505
Electricity generating facilities | Northern California Wildfire
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 850
Electricity generating facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
Electricity generating facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	75 years
Electricity distribution facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 37,723	34,902
Electricity distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	10 years
Electricity distribution facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	70 years
Electricity transmission facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 15,516	14,414
Electricity transmission facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	15 years
Electricity transmission facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	75 years
Natural gas distribution facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 14,100	12,962
Natural gas distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	20 years
Natural gas distribution facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	60 years
Natural gas transmission and storage facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 9,067	8,293
Natural gas transmission and storage facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
Natural gas transmission and storage facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	66 years
Financing lease
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 18	18
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	3,480	2,757
General plant and other
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 7,838	$ 8,041
General plant and other | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
General plant and other | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	50 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO liability at beginning of year	$ 6,412	$ 5,854
Liabilities incurred in the current period	0	268
Revision in estimated cash flows	(1,378)	53
Accretion	287	265
Liabilities settled	(23)	(28)
ARO liability at end of year	$ 5,298	$ 6,412

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ (22)	$ (5)
Net current period other comprehensive income	7	(17)
Ending balance	(15)	(22)
Accumulated Other Comprehensive Income (Loss) | Pension Plan
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(39)	(22)
Net current period other comprehensive income	6	(17)
Ending balance	(33)	(39)
Accumulated Other Comprehensive Income (Loss) | PBOP Plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	17	17
Net current period other comprehensive income	1	0
Ending balance	18	17
Amortization of prior service cost
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income:	6	6
Amortization of prior service cost | Pension Plan
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income:	(4)	(4)
Amounts reclassified from other comprehensive income, tax	2	2
Amortization of prior service cost | PBOP Plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income:	10	10
Amounts reclassified from other comprehensive income, tax	4	4
Amortization of net actuarial gain (loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	1,144	(247)
Amounts reclassified from other comprehensive income:	(20)	(13)
Amortization of net actuarial gain (loss) | Pension Plan
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	1,007	(417)
Amounts reclassified from other comprehensive income:	4	2
Other comprehensive income before reclassifications, tax	391	162
Amounts reclassified from other comprehensive income, tax	2	1
Amortization of net actuarial gain (loss) | PBOP Plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	137	170
Amounts reclassified from other comprehensive income:	(24)	(15)
Other comprehensive income before reclassifications, tax	53	66
Amounts reclassified from other comprehensive income, tax	9	6
Regulatory account transfer
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(1,139)	230
Amounts reclassified from other comprehensive income:	16	7
Regulatory account transfer | Pension Plan
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(1,003)	400
Amounts reclassified from other comprehensive income:	2	2
Other comprehensive income before reclassifications, tax	390	155
Amounts reclassified from other comprehensive income, tax	1	1
Regulatory account transfer | PBOP Plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(136)	(170)
Amounts reclassified from other comprehensive income:	14	5
Other comprehensive income before reclassifications, tax	53	66
Amounts reclassified from other comprehensive income, tax	$ 5	$ 2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Operating lease fixed cost	$ 578	$ 679
Operating lease variable cost	1,782	1,852
Total operating lease costs	$ 2,360	$ 2,531

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Future Expected Operating Lease Payments
2022	$ 533
2023	276
2024	118
2025	111
2026	105
Thereafter	444
Total lease payments	1,587
Less imputed interest	(310)
Total	$ 1,277

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	10 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 9,207.0	$ 9,207.0	$ 8,978.0
Utility retained generation asset costs	1,200.0	1,200.0
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	708.0	708.0	2,245.0
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,089.0	$ 1,089.0	1,112.0
Recovery Period		32 years
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	133.0	$ 133.0	181.0
Recovery Period		6 years
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	216.0	$ 216.0	204.0
Recovery Period		19 years
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	37.0	$ 37.0	49.0
Recovery Period		23 years
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,119.0	$ 1,119.0	842.0
Catastrophic event memorandum account | COVID-19
Regulatory Assets [Line Items]
Total long-term regulatory assets	49.0	$ 49.0	49.0
Catastrophic event memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
Catastrophic event memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period		3 years
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	347.0	$ 347.0	400.0
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	75.0	$ 75.0	137.0
Fire hazard prevention memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
Fire hazard prevention memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period		3 years
Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	44.0	$ 44.0	66.0
Fire risk mitigation memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
Fire risk mitigation memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period		3 years
Wildfire mitigation plan memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	424.0	$ 424.0	390.0
Wildfire mitigation plan memorandum account | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
Wildfire mitigation plan memorandum account | Maximum
Regulatory Assets [Line Items]
Recovery Period		3 years
Deferred income tax
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,849.0	$ 1,849.0	908.0
Recovery Period		51 years
Insurance premium costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	207.0	$ 207.0	294.0
Insurance premium costs | Minimum
Regulatory Assets [Line Items]
Recovery Period		3 years
Insurance premium costs | Maximum
Regulatory Assets [Line Items]
Recovery Period		4 years
Wildfire mitigation balancing account
Regulatory Assets [Line Items]
Total long-term regulatory assets	273.0	$ 273.0	156.0
Wildfire mitigation balancing account | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
Cost percentage threshold requiring approval		115.00%
Wildfire mitigation balancing account | Maximum
Regulatory Assets [Line Items]
Recovery Period		3 years
General rate case memorandum accounts
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 0.0	$ 0.0	376.0
Recovery period	22 months
General rate case memorandum accounts | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
General rate case memorandum accounts | Maximum
Regulatory Assets [Line Items]
Recovery Period		2 years
Vegetation management balancing account
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 1,411.0	$ 1,411.0	592.0
Vegetation management balancing account | Minimum
Regulatory Assets [Line Items]
Recovery Period		1 year
Cost percentage threshold requiring approval		120.00%
Vegetation management balancing account | Maximum
Regulatory Assets [Line Items]
Recovery Period		3 years
COVID-19 Pandemic protection memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	49.0	$ 49.0	84.0
COVID-19 pandemic protection memorandum account, undercollection bad debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	30.0	30.0
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	19.0	19.0
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 1,226.0	$ 1,226.0	$ 942.0

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 11,999	$ 10,424
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	446
Federal Energy Regulatory Commission
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	311
California Public Utilities Commission
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	135
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	7,306	6,905
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	388	458
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	946	948
Employee benefit plans
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	1,229	995
Transmission tower wireless licenses
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	446	0
SFGO sale
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	343	0
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,341	$ 1,118

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Oct. 21, 2021	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Regulatory balancing accounts		$ 496.0	$ 410.0
Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		1,121.0	1,245.0
Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		2,999.0	2,001.0
Electric distribution | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		121.0	55.0
Electric transmission | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		24.0	267.0
Gas distribution and transmission | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		83.0	76.0
Gas distribution and transmission | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		0.0	102.0
Energy procurement | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		211.0	158.0
Energy procurement | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		310.0	413.0
Public purpose programs | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		259.0	410.0
Public purpose programs | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		321.0	292.0
Fire hazard prevention memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		50.0	121.0
Fire risk mitigation memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		14.0	33.0
Wildfire mitigation plan memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		67.0	161.0
Wildfire mitigation balancing account | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		91.0	27.0
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		468.0	313.0
Vegetation management balancing account | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		127.0	115.0
Insurance premium costs
Regulatory Liabilities [Line Items]
Regulatory balancing accounts		82.0
Settlement recovery amount	$ 445.5
Insurance premium costs | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		605.0	135.0
Wildfire expense memorandum account | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		440.0	0.0
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		127.0	0.0
Nuclear decommissioning adjustment mechanism | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		137.0	0.0
Other | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		286.0	279.0
Other | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts		$ 379.0	$ 289.0

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DEBT (Outstanding Borrowings and Availability) (Details) - USD ($)		12 Months Ended
	Feb. 08, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 22, 2021	Jul. 01, 2020
Debt [Line Items]
Repayments of long term debt		$ 87,000,000	$ 764,000,000	$ 0
PG&E Corporation
Debt [Line Items]
Repayments of long term debt		28,000,000	664,000,000	0
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of long term debt		59,000,000	100,000,000	$ 0
Revolving Credit Facility
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		6,941,000,000
Loans Outstanding		4,300,000,000
Letters of Credit Outstanding		692,000,000
Facility Availability		1,923,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		500,000,000				$ 500,000,000
Loans Outstanding		0
Letters of Credit Outstanding		0
Facility Availability		500,000,000
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		4,000,000,000			$ 4,000,000,000	$ 3,500,000,000
Loans Outstanding		1,885,000,000
Letters of Credit Outstanding		692,000,000
Facility Availability		1,423,000,000
Letter of credit sublimit		1,500,000,000
Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		1,441,000,000
Loans Outstanding		1,441,000,000
Letters of Credit Outstanding		0
Facility Availability		0
Term Loan | Pacific Gas & Electric Co (Utility) | Subsequent Event
Debt [Line Items]
Repayments of long term debt	$ 142,500,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		1,000,000,000
Loans Outstanding		974,000,000	$ 1,000,000,000
Letters of Credit Outstanding		0
Facility Availability		$ 0

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DEBT (Narrative) (Details)						1 Months Ended	12 Months Ended
	Feb. 08, 2022 USD ($)	Nov. 15, 2021 USD ($)	Aug. 11, 2021 USD ($)	Jun. 24, 2021 USD ($)	Jul. 01, 2020 USD ($) numberOfClaimHolder numberOfExtensionOption	Mar. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Nov. 12, 2021 USD ($)	Jun. 30, 2021 USD ($)	Jun. 22, 2021 USD ($)	Apr. 23, 2021 USD ($)	Feb. 24, 2021 USD ($)	Apr. 30, 2020 USD ($)
Debt [Line Items]
Repayments of long term debt							$ 87,000,000	$ 764,000,000	$ 0
Intercompany note to PG&E Corporation			$ 145,000,000
2017 Northern California wildfires
Debt [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized													$ 7,500,000,000		$ 7,500,000,000
Customer Harm Threshold, post-emergence transaction, debt retirement															$ 6,000,000,000
2017 Northern California wildfires | Fire Risk Mitigation Capital Expenditures
Debt [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized				$ 1,190,000,000										$ 1,190,000,000
PG&E Corporation
Debt [Line Items]
Repayments of long term debt							28,000,000	664,000,000	0
Intercompany note to PG&E Corporation							(145,000,000)	0	0
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of long term debt							59,000,000	100,000,000	0
Intercompany note to PG&E Corporation							145,000,000	0	$ 0
Revolving Credit Facility
Debt [Line Items]
Line of credit facility, maximum borrowing capacity							6,941,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 500,000,000		500,000,000
Debt, number of extension options | numberOfExtensionOption					2
Debt instrument, extension option, term					1 year
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 3,500,000,000		4,000,000,000					$ 4,000,000,000
Debt, number of extension options | numberOfClaimHolder					2
Debt instrument, extension option, term					1 year
Repayments of debt		$ 300,000,000
Term Loan Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 3,000,000,000
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 1,500,000,000
Debt instrument, term					364 days	364 days
Repayments of debt						$ 1,500,000,000
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity					$ 1,500,000,000
Debt instrument, term					18 months
Intercompany Loan
Debt [Line Items]
Debt instrument, term			364 days
Recovery Bonds | Senior Secured Superpriority Debt
Debt [Line Items]
Debt instrument, face amount							860,000,000	$ 0		$ 860,000,000
Recovery Bonds | Senior Secured Superpriority Debt | Tranche One
Debt [Line Items]
Debt instrument, face amount										$ 266,000,000
Interest rate										1.46%
Recovery Bonds | Senior Secured Superpriority Debt | Tranche Two
Debt [Line Items]
Debt instrument, face amount										$ 160,000,000
Interest rate										2.28%
Recovery Bonds | Senior Secured Superpriority Debt | Tranche Three
Debt [Line Items]
Debt instrument, face amount										$ 434,000,000
Interest rate										2.82%
Recovery Bonds | 2017 Northern California wildfires | Fire Risk Mitigation Capital Expenditures
Debt [Line Items]
Proceeds from issuance of debt				1,200,000,000
Debt issuance costs				$ 13,300,000
First Mortgage Bonds, Exchange Stated Maturity 2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount						$ 1,500,000,000
Interest rate						1.367%
First Mortgage Bonds, Exchange Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount						$ 450,000,000
Interest rate						3.25%
First Mortgage Bonds, Exchange Stated Maturity 2041 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount						$ 450,000,000
Interest rate						4.20%
First Mortgage Bonds, Exchange Stated Maturity 2028
Debt [Line Items]
Debt instrument, face amount											$ 800,000,000
Interest rate											3.00%
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount		300,000,000
First Mortgage Bonds due November 15, 2021 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of debt		1,450,000,000
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount		$ 900,000,000
Interest rate		1.70%
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount		$ 550,000,000
Interest rate		3.25%
Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity							$ 1,441,000,000
Term Loan | Pacific Gas & Electric Co (Utility) | Subsequent Event
Debt [Line Items]
Repayments of long term debt	$ 142,500,000

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DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Nov. 15, 2021	Nov. 12, 2021	Dec. 31, 2020
Debt [Line Items]
Less: current portion, net of debt issuance costs	$ (4,481)			$ (28)
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of debt issuance costs	(4,455)			0
PG&E Corporation
Debt [Line Items]
Less: current portion, net of debt issuance costs	(27)			(28)
New Debt
Debt [Line Items]
Long-term debt, net	38,225			37,288
New Debt | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of debt issuance costs	(1,441)			0
Unamortized discount, net of premium and debt issuance costs	0			(6)
Long-term debt, net	33,632			32,664
New Debt | PG&E Corporation
Debt [Line Items]
Less: current portion, net of debt issuance costs	(26)			0
Unamortized discount, net of premium and debt issuance costs	(90)			(85)
Long-term debt, net	4,593			4,624
Term Loan, Stated Maturity 2025 | PG&E Corporation
Debt [Line Items]
Long-term debt, gross	$ 2,709			$ 2,709
Term Loan, Stated Maturity 2025 | PG&E Corporation | LIBOR
Debt [Line Items]
Stated interest rate	3.50%			5.50%
Senior Notes Due 2028 | PG&E Corporation
Debt [Line Items]
Stated interest rate	5.00%
Long-term debt, gross	$ 1,000			$ 1,000
Senior Notes Due 2030 | PG&E Corporation
Debt [Line Items]
Stated interest rate	5.25%
Long-term debt, gross	$ 1,000			1,000
First Mortgage Bonds | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Less: current portion, net of debt issuance costs	(2,996)			0
Unamortized discount, net of premium and debt issuance costs	(190)			(182)
Long-term debt, net	31,816			30,170
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 500			$ 500
Recovery Bonds		$ 300
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | LIBOR
Debt [Line Items]
Stated interest rate	1.69%			1.70%
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	1.75%
Long-term debt, gross	$ 2,500			$ 2,500
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate		1.70%
Long-term debt, gross	$ 3,575			1,175
Recovery Bonds		$ 900
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	1.37%
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.25%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 800			800
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.40%
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.75%
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,475			1,475
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.45%
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.50%
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,551			2,551
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	2.95%
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.15%
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,550			2,550
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	2.10%
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.30%
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,975			1,175
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.00%
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.65%
First Mortgage Bonds, Stated Maturity 2030 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 3,100			3,100
First Mortgage Bonds, Stated Maturity 2030 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.55%
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate		3.25%
Long-term debt, gross	$ 3,000			2,000
Recovery Bonds		$ 550
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	2.50%
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	3.25%
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 2,951			2,951
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.30%
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.50%
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 700			250
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	4.20%
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.50%
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 750			750
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	3.75%
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.45%
First Mortgage Bonds, Stated Maturity 2043 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.60%
Long-term debt, gross	$ 375			375
First Mortgage Bonds, Stated Maturity 2044 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.75%
Long-term debt, gross	$ 675			675
First Mortgage Bonds, Stated Maturity 2045 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	4.30%
Long-term debt, gross	$ 600			600
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 1,050			1,050
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | Minimum
Debt [Line Items]
Stated interest rate	4.00%
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.25%
First Mortgage Bonds, Stated Maturity 2047 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Stated interest rate	3.95%
Long-term debt, gross	$ 850			850
First Mortgage Bonds, Stated Maturity 2050 | Minimum
Debt [Line Items]
Stated interest rate	3.50%
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 5,025			5,025
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | Maximum
Debt [Line Items]
Stated interest rate	4.95%
Recovery Bonds | Senior Secured Superpriority Debt
Debt [Line Items]
Less: current portion, net of debt issuance costs	$ (18)			0
Recovery Bonds	$ 860		$ 860	0
Recovery Bonds | Minimum | Senior Secured Superpriority Debt
Debt [Line Items]
Stated interest rate	1.46%
Recovery Bonds | Maximum | Senior Secured Superpriority Debt
Debt [Line Items]
Stated interest rate	2.82%
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Long-term debt, gross	$ 974			1,000
Long-term debt, net	$ 974			$ 1,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | LIBOR
Debt [Line Items]
Debt, average interest rate	1.30%			1.57%
18-Months Term Loan | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
18-month Term Loan - Stated Maturity: 2022	$ 1,441			$ 1,500
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | LIBOR
Debt [Line Items]
Stated interest rate	2.38%			2.44%
Debt, average interest rate

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DEBT (Schedule of Contractual Repayment Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Debt [Line Items]
Total consolidated debt	$ 42,126
Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.49%
Fixed rate obligations	$ 34,502
Variable rate obligations	$ 2,915
Pacific Gas & Electric Co (Utility) | 18-Months Term Loan
Debt [Line Items]
Debt Instrument, term	18 months
Pacific Gas & Electric Co (Utility) | 18-Months Term Loan | LIBOR
Debt [Line Items]
Debt, average interest rate
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program | LIBOR
Debt [Line Items]
Debt, average interest rate	1.30%	1.57%
PG&E Corporation
Debt [Line Items]
Average fixed interest rate	5.13%
Fixed rate obligations	$ 2,000
Variable interest rate as of December 31, 2021	3.50%
Variable rate obligations	$ 2,709
2022
Debt [Line Items]
Total consolidated debt	$ 4,469
2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	1.75%
Fixed rate obligations	$ 2,500
Variable interest rate as of December 31, 2021	2.20%
Variable rate obligations	$ 1,941
2022 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2021	3.50%
Variable rate obligations	$ 28
2023
Debt [Line Items]
Total consolidated debt	$ 4,577
2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	2.26%
Fixed rate obligations	$ 3,575
Variable rate obligations	$ 974
2023 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2021	3.50%
Variable rate obligations	$ 28
2024
Debt [Line Items]
Total consolidated debt	$ 828
2024 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.60%
Fixed rate obligations	$ 800
Variable interest rate as of December 31, 2021	0.00%
Variable rate obligations	$ 0
2024 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2021	3.50%
Variable rate obligations	$ 28
2025
Debt [Line Items]
Total consolidated debt	$ 4,100
2025 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.47%
Fixed rate obligations	$ 1,475
Variable interest rate as of December 31, 2021	0.00%
Variable rate obligations	$ 0
2025 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2021	3.50%
Variable rate obligations	$ 2,625
2026
Debt [Line Items]
Total consolidated debt	$ 2,551
2026 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.10%
Fixed rate obligations	$ 2,551
Variable interest rate as of December 31, 2021	0.00%
Variable rate obligations	$ 0
2026 | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Variable interest rate as of December 31, 2021	0.00%
Variable rate obligations	$ 0
Thereafter
Debt [Line Items]
Total consolidated debt	$ 25,601
Thereafter | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Average fixed interest rate	3.90%
Fixed rate obligations	$ 23,601
Variable interest rate as of December 31, 2021	0.00%
Variable rate obligations	$ 0
Thereafter | PG&E Corporation
Debt [Line Items]
Average fixed interest rate	5.13%
Fixed rate obligations	$ 2,000
Variable interest rate as of December 31, 2021	0.00%
Variable rate obligations	$ 0

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COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details)						12 Months Ended			84 Months Ended
	Feb. 08, 2022 USD ($)	Jan. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares	Jul. 09, 2021 USD ($) shares	May 28, 2020	Dec. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2020 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares	Dec. 31, 2021 USD ($) shares	Feb. 04, 2022 shares	Jul. 08, 2021	Apr. 30, 2021 USD ($)	Jul. 01, 2020	Mar. 20, 2020 USD ($)
Schedule of Capitalization, Equity [Line Items]
Common stock, shares outstanding (in shares)			1,985,400,540			1,985,400,540	1,984,678,673		1,985,400,540
Treasury stock, shares at cost (in shares)			477,743,590			477,743,590	0		477,743,590
Shares outstanding (in shares)										2,463,891,104
Common stock, shares issued, reserve, additional shares due to nonconforming new shares (in shares)			0			0			0
Dividend reinstatement target, amount | $														$ 6,200,000,000
Equity capital structure percentage													52.00%
Equity capital structure, waiver period					5 years
Shares available for LTIP award (in shares)			58,552,722			58,552,722			58,552,722
Weighted average grant date fair value of granted shares (in dollars per share) | $ / shares						$ 11.01	$ 9.25	$ 18.57
Total fair value | $						$ 19,000,000	$ 31,000,000	$ 42,000,000
Total unrecognized compensation costs | $						$ 81,000,000
Remaining weighted average period						2 years 2 months 8 days
Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Shares outstanding (in shares)										2,463,891,104
Common stock, shares outstanding, adjusted (in shares)										1,548,403,924
Percentage stock ownership limitation										0.0298
Cumulative and unpaid dividends | $		$ 59,100,000
Preferred stock dividend requirement | $	$ 3,500,000
Fire Victim Trust | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Number of shares exchanged (in shares)		40,000,000
2014 LTIP, Amended
Schedule of Capitalization, Equity [Line Items]
Number of shares issued for LTIP, maximum (in shares)			91,000,000			91,000,000			91,000,000
Stock Options
Schedule of Capitalization, Equity [Line Items]
Granted (in shares)						0	0
Weighted-average period						1 year 5 months 19 days
Stock Options | 2014 LTIP
Schedule of Capitalization, Equity [Line Items]
Term of award						10 years
Award vesting period						3 years
Total unrecognized compensation costs | $			$ 0			$ 0			$ 0
Granted (in shares)						0
Restricted stock units
Schedule of Capitalization, Equity [Line Items]
Award vesting period									3 years
Tax detriment | $						$ 11,000,000
Performance shares
Schedule of Capitalization, Equity [Line Items]
Award vesting period						3 years
Tax detriment | $						$ 19,000,000
Industry performance period						3 years
Award grant date fair value recognition period						3 years
Performance shares granted (in dollars per share) | $ / shares						$ 11.83	$ 9.62	$ 15.39
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized | $						$ 50,000,000
PG&E ShareCo | Common Stock
Schedule of Capitalization, Equity [Line Items]
Stock issued during period, shares, new issues (in shares)						477,743,590
PG&E ShareCo | Fire Victim Trust Share Exchange and Tax Matters Agreement | Common Stock
Schedule of Capitalization, Equity [Line Items]
Stock issued during period, shares, new issues (in shares)				477,743,590
Transfer of shares to Fire Victim Trust (in shares)			477,743,590			477,743,590			477,743,590
PG&E Corporation
Schedule of Capitalization, Equity [Line Items]
Increase in common stock | $				$ 4,850,000,000
PG&E Corporation | Equity Units
Schedule of Capitalization, Equity [Line Items]
Stock issued during period, shares, new issues (in shares)							16,000,000
PG&E Corporation | Minimum
Schedule of Capitalization, Equity [Line Items]
Percentage of equity security ownership with board of director approval			4.75%			4.75%			4.75%		4.75%
PG&E Corporation | Minimum | Common Stock
Schedule of Capitalization, Equity [Line Items]
Amount of shares, right to receive							138,000,000
PG&E Corporation | Minimum | Revolving Credit Facility
Schedule of Capitalization, Equity [Line Items]
Debt, ratio of total consolidated debt to consolidated capitalization, loans outstanding balance													150.00%
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared													100.00%
PG&E Corporation | Maximum | Common Stock
Schedule of Capitalization, Equity [Line Items]
Amount of shares, right to receive							168,000,000
PG&E Corporation | Maximum | Revolving Credit Facility
Schedule of Capitalization, Equity [Line Items]
Debt, ratio of total consolidated debt to consolidated capitalization													70.00%
PG&E Corporation | Maximum | Fire Victim Trust Share Exchange and Tax Matters Agreement
Schedule of Capitalization, Equity [Line Items]
Common stock, shares authorized, reserve, additional shares due to nonconforming new shares (in shares)			250,000,000
PG&E Corporation | At The Market Equity Distribution Program | Common Stock
Schedule of Capitalization, Equity [Line Items]
Sale of stock, number of shares issued in transaction, amount | $			$ 400,000,000			$ 400,000,000			$ 400,000,000			$ 400,000,000

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COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 56	$ 35	$ 50
Total compensation expense (after-tax)	40	25	35
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	0	3	7
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	35	15	21
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 21	$ 17	$ 22

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COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Number of Stock Options
Granted (in shares)	0	0
2014 LTIP
Number of Stock Options
Outstanding, beginning of period (in shares)	2,221,247
Granted (in shares)	0
Exercised (in shares)	0
Forfeited or expired (in shares)	(25,413)
Outstanding, end of period (in shares)	2,195,834	2,221,247
Vested or expected to vest (in shares)	2,195,834
Exercisable (in shares)	2,195,834
Weighted Average Grant- Date Fair Value
Outstanding, beginning of period (in dollars per share)	$ 7.45
Forfeited or expired (in dollars per share)	10.23
Outstanding, end of period (in dollars per share)	7.42	$ 7.45
Vested or expected to vest (in dollars per share)	7.42
Exercisable (in dollars per share)	$ 7.42
Weighted Average Remaining Contractual Term
Outstanding	4 years 3 months 29 days
Expected to vest	4 years 3 months 29 days
Exercisable	4 years 3 months 29 days

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COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Restricted Stock Units
Nonvested, beginning balance (in shares)	890,353
Granted (in shares)	10,352,117
Vested (in shares)	(743,672)
Forfeited (in shares)	(408,423)
Nonvested, ending balance (in shares)	10,090,375	890,353
Weighted Average Grant- Date Fair Value
Nonvested, beginning balance (in dollars per share)	$ 23.05
Granted (in dollars per share)	11.01	$ 9.25	$ 18.57
Vested (in dollars per share)	25.20
Forfeited (in dollars per share)	11.67
Nonvested, ending balance (in dollars per share)	$ 11.00	$ 23.05

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COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Number of Performance Shares
Nonvested , beginning balance (in shares)	7,288,782
Granted (in shares)	2,714,645
Vested (in shares)	0
Forfeited (in shares)	(1,436,418)
Nonvested, ending balance (in shares)	8,567,009	7,288,782
Weighted Average Grant- Date Fair Value
Nonvested, beginning balance (in dollars per share)	$ 9.16
Granted (in dollars per share)	11.83	$ 9.62	$ 15.39
Vested (in dollars per share)	0
Forfeited (in dollars per share)	11.35
Nonvested, ending balance (in dollars per share)	9.64	$ 9.16
Expirations, fair value (in dollars per share)	$ 0

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PREFERRED STOCK (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Feb. 08, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 31, 2022
Subsequent Event
Preferred Stock [Line Items]
Cumulative and unpaid dividends					$ 59.1
Preferred stock dividend requirement	$ 3.5
Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock dividend requirement		$ 14.0	$ 14.0	$ 14.0
Pacific Gas & Electric Co (Utility) | Minimum
Preferred Stock [Line Items]
Redemption price (in dollars per share)		$ 25.75	$ 25.75
Pacific Gas & Electric Co (Utility) | Maximum
Preferred Stock [Line Items]
Redemption price (in dollars per share)		$ 27.25	$ 27.25
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock
Preferred Stock [Line Items]
Nonredeemable preferred stock outstanding		$ 145.0	$ 145.0
Preferred stock dividends per share, low range (in dollars per share)		$ 1.25
Preferred stock dividends per share, high range (in dollars per share)		$ 1.50
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate		5.00%	5.00%
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Maximum
Preferred Stock [Line Items]
Preferred stock interest rate		6.00%	6.00%
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock
Preferred Stock [Line Items]
Redeemable preferred stock outstanding		$ 113.0	$ 113.0
Preferred stock dividends per share, low range (in dollars per share)		$ 1.09
Preferred stock dividends per share, high range (in dollars per share)		$ 1.25
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate		4.36%	4.36%
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Maximum
Preferred Stock [Line Items]
Preferred stock interest rate		5.00%	5.00%
PG&E Corporation
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)		400,000,000
Preferred stock, shares outstanding (in shares)		0
$25 Par Value | Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)		75,000,000
Preferred stock, par value (in dollars per share)		$ 25
$100 Par Value | Pacific Gas & Electric Co (Utility)
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)		10,000,000
Preferred stock, shares outstanding (in shares)		0
Preferred stock, par value (in dollars per share)		$ 100

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EARNINGS PER SHARE (Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Shares of Common Stock Outstanding for Calculating Diluted EPS) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Abstract]
Loss attributable to common shareholders	$ (102)	$ (1,318)	$ (7,656)
Weighted average common shares outstanding, basic (in shares)	1,985	1,257	528
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	0	0	0
Equity Units (in shares)	0	0	0
Weighted average common share outstanding, diluted (in shares)	1,985	1,257	528
Total Loss per common share, diluted (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)

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INCOME TAXES (Schedule of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current:
Federal	$ 0	$ (26)	$ 1
State	1	(34)	101
Deferred:
Federal	543	258	(2,361)
State	296	171	(1,136)
Tax credits	(4)	(7)	(5)
Income tax provision (benefit)	836	362	(3,400)
Pacific Gas & Electric Co (Utility)
Current:
Federal	0	(26)	4
State	0	(34)	94
Deferred:
Federal	588	290	(2,363)
State	316	185	(1,137)
Tax credits	(4)	(7)	(5)
Income tax provision (benefit)	$ 900	$ 408	$ (3,407)

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INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pacific Gas & Electric Co (Utility)
Deferred income tax assets:
Tax carryforwards	$ 5,425	$ 7,529
Compensation	108	109
Wildfire-related claims	1,723	544
Operating lease liability	346	488
Transmission tower wireless licenses	266	0
Other	293	219
Total deferred income tax assets	8,161	8,889
Deferred income tax liabilities:
Property related basis differences	8,835	8,300
Regulatory balancing accounts	1,193	763
Debt financing costs	501	526
Operating lease right of use asset	346	488
Income tax regulatory asset	517	254
Other	178	128
Total deferred income tax liabilities	11,570	10,459
Total net deferred income tax liabilities	3,409	1,570
PG&E Corporation
Deferred income tax assets:
Tax carryforwards	5,628	7,641
Compensation	185	187
Wildfire-related claims	1,723	544
Operating lease liability	346	489
Transmission tower wireless licenses	266	0
Other	278	212
Total deferred income tax assets	8,426	9,073
Deferred income tax liabilities:
Property related basis differences	8,847	8,311
Regulatory balancing accounts	1,193	763
Debt financing costs	501	526
Operating lease right of use asset	346	489
Income tax regulatory asset	517	254
Other	199	128
Total deferred income tax liabilities	11,603	10,471
Total net deferred income tax liabilities	$ 3,177	$ 1,398

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INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pacific Gas & Electric Co (Utility)
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate	21.00%	21.00%	21.00%
State income tax (net of federal benefit)	24.10%	19.10%	7.50%
Effect of regulatory treatment of fixed asset differences	(51.60%)	(44.90%)	2.80%
Tax credits	1.20%	1.70%	0.10%
Fire Victim Trust	0.919	0.517	0
Bankruptcy and emergence	0.00%	2.40%	0.00%
Other, net	2.60%	2.20%	(0.50%)
Effective tax rate	86.80%	49.80%	30.90%
PG&E Corporation
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate	21.00%	21.00%	21.00%
State income tax (net of federal benefit)	31.30%	(15.30%)	7.50%
Effect of regulatory treatment of fixed asset differences	(71.50%)	39.00%	2.80%
Tax credits	(1.70%)	1.50%	0.10%
Fire Victim Trust	1.273	(0.449)	0
Bankruptcy and emergence	0.00%	(37.60%)	0.00%
Other, net	5.30%	(2.10%)	(0.60%)
Effective tax rate	111.70%	(38.40%)	30.80%

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INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pacific Gas & Electric Co (Utility)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	$ 437	$ 420	$ 377
Reductions for tax position taken during a prior year	(23)	(43)	(1)
Additions for tax position taken during the current year	85	60	44
Settlements	(1)	0	0
Balance, end of period	498	437	420
PG&E Corporation
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	437	420	377
Reductions for tax position taken during a prior year	(23)	(43)	(1)
Additions for tax position taken during the current year	85	60	44
Settlements	(1)	0	0
Balance, end of period	$ 498	$ 437	$ 420

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INCOME TAXES (Narrative) (Details) - USD ($) shares in Millions, $ in Millions		2 Months Ended	12 Months Ended
	Jan. 31, 2022	Feb. 25, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jul. 01, 2020
Investments, Owned, Federal Income Tax Note [Line Items]
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year			$ 30
Decrease in net operating loss			1,883	$ 1,755	$ (10,094)
Fire Victim Trust
Investments, Owned, Federal Income Tax Note [Line Items]
Cash contribution by company						$ 5,400
Stock contribution by company (in shares)						4,540
Decrease in net operating loss		$ 10,000
Payments made to Fire Victim Trust			$ 1,670
Decrease in net operating loss, tax		$ 1,300
Fire Victim Trust | Subsequent Event
Investments, Owned, Federal Income Tax Note [Line Items]
Number of shares exchanged (in shares)	40

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INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	$ 144
Federal | Pre-2018
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	3,600
Federal | Post-2017
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	17,467
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	18,853
Tax credit carryforward	$ 122

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DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details)	Dec. 31, 2021 MMBTU MWh	Dec. 31, 2020 MMBTU MWh
Forwards, Futures and Swaps | Natural Gas (MMBtus)
Derivative [Line Items]
Contract Volume	173,361,635	146,642,863
Forwards, Futures and Swaps | Electricity (Megawatt-hours)
Derivative [Line Items]
Contract Volume | MWh	10,283,639	9,435,830
Options | Natural Gas (MMBtus)
Derivative [Line Items]
Contract Volume	14,420,000	14,140,000
Options | Electricity (Megawatt-hours)
Derivative [Line Items]
Contract Volume	288,000	0
Congestion revenue rights | Electricity (Megawatt-hours)
Derivative [Line Items]
Contract Volume | MWh	239,857,610	266,091,470

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DERIVATIVES (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives And Hedging Activities [Line Items]
Netting	$ 143	$ 115
Netting	27	25
Commodity Contract | Pacific Gas & Electric Co (Utility)
Derivatives And Hedging Activities [Line Items]
Netting	(42)	(73)
Netting	0	0
Cash Collateral	170	140
Total Derivative Balance	128	67
Commodity Contract | Pacific Gas & Electric Co (Utility) | Current assets – other
Derivatives And Hedging Activities [Line Items]
Netting	58	33
Netting	(9)	0
Cash Collateral	152	115
Total Derivative Balance	201	148
Commodity Contract | Pacific Gas & Electric Co (Utility) | Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Netting	169	136
Netting	0	0
Cash Collateral	0	0
Total Derivative Balance	169	136
Commodity Contract | Pacific Gas & Electric Co (Utility) | Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(53)	(38)
Netting	9	0
Cash Collateral	18	15
Total Derivative Balance	(26)	(23)
Commodity Contract | Pacific Gas & Electric Co (Utility) | Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(216)	(204)
Netting	0	0
Cash Collateral	0	10
Total Derivative Balance	$ (216)	$ (194)

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FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	$ 289	$ 470
Total nuclear decommissioning trusts	4,581	4,209
Rabbi trusts	180	185
Long-term disability trust	138	167
Netting	143	115
TOTAL ASSETS	5,558	5,315
Netting	(27)	(25)
Amount primarily related to deferred taxes on appreciation of investment value	783	671
Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	6	2
Netting	(24)	(25)
Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting	137	113
Netting	(3)	0
Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	22	27
Long-term disability trust	6	9
Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	2,504	2,398
Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	2,024	1,759
Rabbi trusts	104	106
Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	370	284
TOTAL LIABILITIES	242	217
Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	229	170
TOTAL LIABILITIES	235	214
Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	141	114
TOTAL LIABILITIES	7	3
Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	76	79
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	289	470
Total nuclear decommissioning trusts	3,684	3,349
Rabbi trusts	0	0
Long-term disability trust	6	9
TOTAL ASSETS	3,979	3,828
Level 1 | Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	22	27
Long-term disability trust	6	9
Level 1 | Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	2,504	2,398
Level 1 | Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	1,158	924
Rabbi trusts	0	0
Level 1 | Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	0	0
Level 1 | Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	0	0
Level 1 | Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	0	0
Level 1 | Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0	0
Total nuclear decommissioning trusts	866	835
Rabbi trusts	180	185
Long-term disability trust	0	0
TOTAL ASSETS	1,059	1,023
Level 2 | Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Long-term disability trust	0	0
Level 2 | Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Level 2 | Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	866	835
Rabbi trusts	104	106
Level 2 | Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	13	3
TOTAL LIABILITIES	21	4
Level 2 | Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	9	2
TOTAL LIABILITIES	11	1
Level 2 | Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	4	1
TOTAL LIABILITIES	10	3
Level 2 | Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	76	79
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0	0
Total nuclear decommissioning trusts	0	0
Rabbi trusts	0	0
Long-term disability trust	0	0
TOTAL ASSETS	214	166
Level 3 | Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Long-term disability trust	0	0
Level 3 | Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Level 3 | Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Rabbi trusts	0	0
Level 3 | Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	214	166
TOTAL LIABILITIES	248	238
Level 3 | Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	214	166
TOTAL LIABILITIES	248	238
Level 3 | Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	0	0
Level 3 | Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	0	0
Assets measured at NAV
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	31	25
Long-term disability trust	$ 132	$ 158

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FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	Dec. 31, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($) $ / shares
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 188	$ 153
Liabilities | $	93	74
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	26	13
Liabilities | $	$ 155	$ 164
CRR auction prices | Market approach | Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	(40.77)	(320.25)
CRR auction prices | Market approach | Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	2,265.94	320.25
CRR auction prices | Market approach | Congestion revenue rights | Weighted average price
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	0.40	0.30
Forward prices | Discounted cash flow | Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	(7.97)	12.56
Forward prices | Discounted cash flow | Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	256.20	148.30
Forward prices | Discounted cash flow | Power purchase agreements | Weighted average price
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh)	47.17	35.52

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FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Asset (liability) balance, beginning of period	$ (72)	$ 5
Included in regulatory assets and liabilities or balancing accounts	38	(77)
Asset (liability) balance, end of period	$ (34)	$ (72)

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FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Carrying Amount
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 4,619	$ 1,901
Carrying Amount | Pacific Gas & Electric Co (Utility)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	31,816	29,664
Level 2 | Level 2 Fair Value
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	4,796	2,175
Level 2 | Level 2 Fair Value | Pacific Gas & Electric Co (Utility)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 35,803	$ 32,632

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FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 2,439	$ 2,180
Total Unrealized Gains	2,164	2,033
Total Unrealized Losses	(22)	(4)
Total Fair Value	4,581	4,209
Amount primarily related to deferred taxes on appreciation of investment value	783	671
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	22	27
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	22	27
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	479	543
Total Unrealized Gains	2,066	1,881
Total Unrealized Losses	(10)	(1)
Total Fair Value	2,535	2,423
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,938	1,610
Total Unrealized Gains	98	152
Total Unrealized Losses	(12)	(3)
Total Fair Value	$ 2,024	$ 1,759

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FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 4,581	$ 4,209
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	97
1–5 years	495
5–10 years	480
More than 10 years	952
Total maturities of fixed-income securities	$ 2,024	$ 1,759

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FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning investments	$ 1,678	$ 1,518	$ 956
Gross realized gains on securities	286	159	69
Gross realized losses on securities	$ (19)	$ (41)	$ (14)

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EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Funded Status:
Noncurrent liability	$ (860)	$ (2,444)
Pension Plan
Change in plan assets:
Fair value of plan assets at beginning of year	20,759	18,547
Actual return on plan assets	1,693	2,736
Company contributions	335	343
Benefits and expenses paid	(892)	(867)
Fair value of plan assets at end of year	21,895	20,759	$ 18,547
Change in benefit obligation:
Benefit obligation at beginning of year	23,172	20,525
Service cost for benefits earned	587	530	443
Interest cost	645	713	758
Actuarial (gain) loss	(752)	2,271
Plan amendments	0	0
Benefits and expenses paid	(893)	(867)
Benefit obligation at end of year	22,759	23,172	20,525
Funded Status:
Current liability	(9)	(3)
Noncurrent liability	(856)	(2,410)
Net (liability) asset at end of year	(865)	(2,413)
Accumulated benefit obligation	20,400	20,700
PBOP Plans
Change in plan assets:
Fair value of plan assets at beginning of year	2,995	2,678
Actual return on plan assets	193	379
Company contributions	10	26
Plan participant contribution	80	81
Benefits and expenses paid	(176)	(169)
Fair value of plan assets at end of year	3,102	2,995	2,678
Change in benefit obligation:
Benefit obligation at beginning of year	1,876	1,832
Service cost for benefits earned	63	61	56
Interest cost	51	63	76
Actuarial (gain) loss	(152)	(14)
Benefits and expenses paid	(156)	(149)
Federal subsidy on benefits paid	4	3
Plan participant contributions	80	80
Benefit obligation at end of year	1,766	1,876	$ 1,832
Funded Status:
Noncurrent asset	1,340	1,153
Noncurrent liability	(4)	(34)
Net (liability) asset at end of year	1,336	1,119
PBOP Plans | Postretirement Life Insurance Plan
Change in plan assets:
Fair value of plan assets at beginning of year	343
Fair value of plan assets at end of year	359	343
Change in benefit obligation:
Benefit obligation at beginning of year	377
Benefit obligation at end of year	$ 363	$ 377

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EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 587	$ 530	$ 443
Interest cost	645	713	758
Expected return on plan assets	(1,046)	(1,044)	(906)
Amortization of prior service cost	(6)	(6)	(6)
Amortization of net actuarial loss	6	3	3
Net periodic benefit cost	186	196	292
Less: transfer to regulatory account	147	136	42
Total expense recognized	333	332	334
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	63	61	56
Interest cost	51	63	76
Expected return on plan assets	(137)	(138)	(123)
Amortization of prior service cost	14	14	14
Amortization of net actuarial loss	(33)	(21)	(3)
Net periodic benefit cost	$ (42)	$ (21)	$ 20

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EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	9.60%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.03%	2.77%	3.46%
Rate of future compensation increases	3.80%	3.80%	3.90%
Expected return on plan assets	5.50%	5.10%	5.70%
Interest crediting rate for cash balance plan	1.95%	1.95%	2.11%
PBOP Plans | Minimum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.97%	2.67%	3.37%
Expected return on plan assets	3.30%	3.10%	3.50%
PBOP Plans | Maximum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.04%	2.80%	3.47%
Expected return on plan assets	6.40%	6.10%	6.60%

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EMPLOYEE BENEFIT PLANS (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) noncallable_bond	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Assumed health care cost trend rate	6.00%
Ultimate trend rate	4.50%
Assumed return	5.50%
10 year actual rate of return	9.60%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond	817
Total fair value of trust other net liabilities	$ (175)	$ 249
Retirement savings plan expense	$ 133	$ 119	$ 109
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
10 year actual rate of return	5.50%	5.10%	5.70%
Company contributions	$ 335	$ 343
Expected employer contribution next year	327
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Company contributions	10	$ 26
Expected employer contribution next year	$ 15

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EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		100.00%	100.00%
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		30.00%	30.00%
Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		2.00%	2.00%
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		8.00%	8.00%
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		60.00%	60.00%
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		100.00%	100.00%
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		36.00%	28.00%
PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		1.00%	2.00%
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		5.00%	8.00%
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		58.00%	62.00%
Forecast | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	100.00%
Forecast | Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	30.00%
Forecast | Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	2.00%
Forecast | Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	8.00%
Forecast | Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	60.00%
Forecast | PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	100.00%
Forecast | PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	26.00%
Forecast | PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	1.00%
Forecast | PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	3.00%
Forecast | PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	70.00%

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EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	$ 25,172	$ 24,003
Level 3
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	27	12	$ 15
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	22,054	20,993
Assets measured at NAV	21,895	20,759	18,547
Pension Plan | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	807	742
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,498	1,875
Pension Plan | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	2
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	632	517
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	10,144	9,633
Pension Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	5,987	5,194
Pension Plan | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	552	334
Pension Plan | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,074	1,875
Pension Plan | Level 1 | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	1
Pension Plan | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	632	517
Pension Plan | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,729	2,467
Pension Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8,068	7,563
Pension Plan | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	255	408
Pension Plan | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	424	0
Pension Plan | Level 2 | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	1
Pension Plan | Level 2 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 2 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	7,388	7,154
Pension Plan | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	27	12
Pension Plan | Level 3 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Absolute Return
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	27	12
Pension Plan | Assets measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	7,972	8,224
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	3,118	3,010
Assets measured at NAV	3,102	2,995	$ 2,678
PBOP Plans | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	31	37
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	105	173
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	34	54
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,652	1,197
PBOP Plans | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	946	745
PBOP Plans | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	31	37
PBOP Plans | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	105	173
PBOP Plans | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	34	54
PBOP Plans | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	776	481
PBOP Plans | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	875	715
PBOP Plans | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	875	715
PBOP Plans | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	1
PBOP Plans | Level 3 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	1
PBOP Plans | Assets measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	$ 1,296	$ 1,549

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EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets at beginning of year	$ 12	$ 15
Actual return on plan assets:
Relating to assets still held at the reporting date	6	2
Relating to assets sold during the period	(7)	(3)
Purchases, issuances, sales, and settlements:
Purchases	22	11
Settlements	(6)	(13)
Fair value of plan assets at end of year	$ 27	$ 12

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EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2022	$ 869
2023	954
2024	988
2025	1,018
2026	1,046
Thereafter in the succeeding five years	5,533
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
2022	81
2023	85
2024	89
2025	88
2026	91
Thereafter in the succeeding five years	466
Federal Subsidy
Defined Benefit Plan Disclosure [Line Items]
2022	(3)
2023	(3)
2024	(3)
2025	(3)
2026	(3)
Thereafter in the succeeding five years	$ (3)

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Administrative services provided to PG&E Corporation
Related Party Transaction [Line Items]
Utility revenues from	$ 3	$ 3	$ 4
Administrative services received from PG&E Corporation
Related Party Transaction [Line Items]
Utility expenses from	82	108	107
Utility employee benefit due to PG&E Corporation
Related Party Transaction [Line Items]
Utility expenses from	$ 39	$ 34	$ 42

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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
	Aug. 11, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Intercompany note to PG&E Corporation	$ 145
Intercompany Loan
Related Party Transaction [Line Items]
Debt Instrument, term	364 days
Pacific Gas & Electric Co (Utility)
Related Party Transaction [Line Items]
Current receivables		$ 173	$ 35
Current payables		19	46
Intercompany note to PG&E Corporation		$ 145	$ 0	$ 0

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WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire, 2020 Zogg Fire and 2021 Dixie Fire) (Details) numberOfPeople in Millions, $ in Millions				3 Months Ended		12 Months Ended
	Oct. 29, 2021 USD ($) a	Oct. 18, 2021 USD ($)	Nov. 04, 2019 numberOfPeople	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Feb. 03, 2022 complaint numberOfClaimHolder plaintiff numberOfPlaintiff	Jan. 28, 2022 count notice	Jan. 27, 2022 notice	Dec. 02, 2021 transmissionLine	Nov. 18, 2021 notice	Sep. 24, 2021 felony misdemeanor	Jul. 13, 2021 a fatality structure	May 11, 2021 count	Apr. 06, 2021 felony misdemeanor	Sep. 27, 2020 a injury fatality structure	Dec. 31, 2019 USD ($)	Oct. 23, 2019 a injury numberOfFatality structure
Loss Contingencies [Line Items]
Insurance receivable				$ 1,247.0		$ 1,247.0	$ 674.0											$ 2,238.0
2019 Kincade fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a																			77,758
Number of fatalities (fatality) | numberOfFatality																			0
Number of injuries | injury																			4
Number of structures destroyed (structure) | structure																			374
Number of structures damaged (structure) | structure																			60
Number of people part of mandatory evacuation order | numberOfPeople			0.2
Number of transmission lines | transmissionLine											70
Loss contingency liability				769.0		769.0	625.0											0.0
Fire fighting costs recovery requested		$ 90.0
Potential loss contingency, additional						175.0
Potential loss contingency						800.0
Insurance receivable				414.0		414.0	430.0											0.0
Insurance receivable				430.0		430.0
2019 Kincade fire | Subsequent Event
Loss Contingencies [Line Items]
Number of felonies (felony) | notice									5	2
Number of demurrer filed (count) | count									22
Number of criminal complaints (count) | count									30
Number of misdemeanors dropped (misdemeanor) | notice									6
Number of complaints (complaint) | complaint								100
Number of plaintiffs represented by complaints | plaintiff								2,605
2019 Kincade fire | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Number of demurrer filed (count) | count															25
Number of criminal complaints (count) | count															33
Loss contingency liability				40.0		40.0
May not seek recovery to remove permanently abandoned transmission lines						85.0
2019 Kincade fire | Pacific Gas & Electric Co (Utility) | Sonoma Contry District Attorney
Loss Contingencies [Line Items]
Number of felonies (felony) | felony																5
Number of misdemeanors (misdemeanor) | misdemeanor																28
2020 Zogg fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a																	56,338
Number of fatalities (fatality) | fatality																	4
Number of injuries | injury																	1
Number of structures destroyed (structure) | structure																	204
Number of structures damaged (structure) | structure																	27
Number of demurrer filed (count) | notice												10
Number of criminal complaints (count) | notice												31
Loss contingency liability				211.0		211.0	275.0											0.0
Potential loss contingency, additional					$ 100.0
Potential loss contingency						375.0	275.0
Insurance receivable				270.0		270.0	219.0											0.0
Liability insurance coverage				611.0		611.0
Initial self-insured retention per occurrence				60.0		60.0
Legal fees						22.0
Insurance receivable				337.0		337.0
2020 Zogg fire | Subsequent Event
Loss Contingencies [Line Items]
Number of complaints (complaint) | complaint								21
Number of plaintiffs represented by complaints | numberOfPlaintiff								382
2020 Zogg fire | Maximum
Loss Contingencies [Line Items]
Liability insurance coverage							867.5
Zogg Complaint, 2020
Loss Contingencies [Line Items]
Number of felonies (felony) | felony													11
Number of misdemeanors (misdemeanor) | misdemeanor													20
2021 Dixie fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a														963,309
Number of fatalities (fatality) | fatality														1
Number of structures destroyed (structure) | structure														1,329
Number of structures damaged (structure) | structure														95
May not seek recovery to remove permanently abandoned transmission lines	$ 630.0
Potential loss contingency				1,150.0
Insurance receivable				563.0		563.0	$ 0.0											$ 0.0
Number of residential structures destroyed (structure) | structure														717
Number of commercial structures destroyed (structure) | structure														143
Number of other structures destroyed (structure) | structure														443
Insurance receivable				563.0		563.0
Probable of recovery						1,161.0
2021 Dixie fire | Subsequent Event
Loss Contingencies [Line Items]
Number of complaints (complaint) | numberOfClaimHolder								20
Number of plaintiffs represented by complaints | numberOfClaimHolder								1,005
2021 Dixie fire | FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery						101.0
2021 Dixie fire | WEMA
Loss Contingencies [Line Items]
Probable of recovery						347.0
2021 Dixie fire | National Park
Loss Contingencies [Line Items]
Number of acres burned (acre) | a	70,000
2021 Dixie fire | National Forrest
Loss Contingencies [Line Items]
Number of acres burned (acre) | a	685,000
Zogg Fire, 2020 and Dixie Fire, 2021
Loss Contingencies [Line Items]
Liability insurance coverage				$ 900.0		$ 900.0

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WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) - 2021 Dixie fire $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Loss Contingencies [Line Items]
Probable of recovery	$ 1,161
Insurance
Loss Contingencies [Line Items]
Probable of recovery	563
FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery	101
WEMA
Loss Contingencies [Line Items]
Probable of recovery	347
Wildfire Fund
Loss Contingencies [Line Items]
Probable of recovery	$ 150

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WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
2019 Kincade fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	$ 625	$ 0
Accrued Losses	175	625
Payments	(31)	0
Loss accrual, ending balance	769	625
2019 Kincade fire | Pacific Gas & Electric Co (Utility)
Loss Contingency Accrual [Roll Forward]
Loss accrual, ending balance	40
2020 Zogg fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	275	0
Accrued Losses	100	275
Payments	(164)	0
Loss accrual, ending balance	$ 211	$ 275

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WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Apr. 29, 2021	Jun. 30, 2021	Dec. 31, 2021	Aug. 31, 2020
Loss Contingencies [Line Items]
Prepaid insurance			$ 358
Insurance premium costs, recovery, coverage amount			1,400
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Initial self-insured retention per occurrence			60
Insurance Coverage for Wildfire Events | August 1, 2019 through July 31, 2020
Loss Contingencies [Line Items]
Liability insurance coverage	$ 268
Reinsurance	32
Costs for insurance coverage	$ 220
Insurance Coverage for Wildfire Events | September 3, 2019 through September 2, 2020
Loss Contingencies [Line Items]
Reinsurance				$ 11
Insurance Coverage for Wildfire Events | August 1, 2019 through July 31, 2020
Loss Contingencies [Line Items]
Liability insurance coverage				$ 600
Insurance Coverage for Wildfire Events | August 1, 2019 through September 2, 2020
Loss Contingencies [Line Items]
Costs for insurance coverage			$ 516
Insurance Coverage for Wildfire Events | July 1, 2020 - June 30, 2021
Loss Contingencies [Line Items]
Costs for insurance coverage		$ 89
Insurance Coverage For Non-Wildfire Liabilities
Loss Contingencies [Line Items]
Initial self-insured retention per occurrence		10
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2019 through July 31, 2020
Loss Contingencies [Line Items]
Liability insurance coverage		50
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2019 through July 31, 2020
Loss Contingencies [Line Items]
Liability insurance coverage		140
Insurance Coverage For Non-Wildfire Liabilities | July 1, 2020 - June 30, 2021
Loss Contingencies [Line Items]
Liability insurance coverage		535
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2020 - July 31, 2021
Loss Contingencies [Line Items]
Costs for insurance coverage		$ 30

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WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
	Jan. 26, 2022	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			$ 674.0	$ 2,238.0
Accrued insurance recoveries			681.0	649.0
Reimbursements			(108.0)	(2,213.0)
Insurance Receivable, Ending Balance		$ 1,247.0	1,247.0	674.0
2021 Dixie fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			0.0	0.0
Accrued insurance recoveries			563.0	0.0
Reimbursements			0.0	0.0
Insurance Receivable, Ending Balance		563.0	563.0	0.0
Insurance receivable		563.0	563.0
Accrued insurance recoveries, increase (decrease)		(6.5)
2020 Zogg fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			219.0	0.0
Accrued insurance recoveries			118.0	219.0
Reimbursements			(67.0)	0.0
Insurance Receivable, Ending Balance		270.0	270.0	219.0
Insurance receivable		337.0	337.0
Accrued insurance recoveries, increase (decrease)		6.5
2020 Zogg fire | Subsequent Event
Insurance Receivable [Roll Forward]
Reimbursements	$ (43.0)
2019 Kincade fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			430.0	0.0
Accrued insurance recoveries			0.0	430.0
Reimbursements			(16.0)	0.0
Insurance Receivable, Ending Balance		414.0	414.0	430.0
Insurance receivable		430.0	430.0
2018 Camp fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			0.0	1,380.0
Accrued insurance recoveries			0.0	0.0
Reimbursements			0.0	(1,380.0)
Insurance Receivable, Ending Balance		0.0	0.0	0.0
2017 Northern California wildfires
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			25.0	808.0
Accrued insurance recoveries			0.0	0.0
Reimbursements			(25.0)	(783.0)
Insurance Receivable, Ending Balance		0.0	0.0	25.0
2015 Butte fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance			0.0	50.0
Accrued insurance recoveries			0.0	0.0
Reimbursements			0.0	(50.0)
Insurance Receivable, Ending Balance		$ 0.0	$ 0.0	$ 0.0

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WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) - 2021 Dixie fire $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Loss Contingencies [Line Items]
Probable of recovery	$ 1,161
FERC TO rates
Loss Contingencies [Line Items]
Probable of recovery	101
WEMA
Loss Contingencies [Line Items]
Probable of recovery	$ 347

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WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions	Aug. 23, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jul. 12, 2019
Loss Contingencies [Line Items]
Disallowance cap, transmission and distribution equity rate base					$ 2,900
Initial safety certification, documentation provided, period	90 days
Initial safety certification, period	12 months
Expected capitalization, proceeds of bond		$ 10,500
Expected capitalization, initial contribution		7,500
Expected capitalization, annual contribution		300
Insurance receivable		1,247	$ 674	$ 2,238
2021 Dixie fire
Loss Contingencies [Line Items]
Insurance receivable		$ 563	$ 0	$ 0

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) - Breach of Fiduciary Duties	Feb. 24, 2021 notice	Nov. 20, 2017 lawsuit	Nov. 16, 2017 lawsuit
Loss Contingencies [Line Items]
Number of causes of action (causes) | notice	2
Derivative Lawsuits Filed in the San Francisco County Superior Court
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit		2	2

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation and Debt Claims) (Details)	Dec. 31, 2021 lawsuit	Feb. 22, 2019 offering	Jun. 30, 2018 lawsuit
Wildfire-Related Class Action
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)			2
Number of public offerings of notes with complaints against underwriters (offering) | offering		4
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	3

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WILDFIRE-RELATED CONTINGENCIES (De-energization Class Action) (Details) $ in Millions	Nov. 02, 2021 USD ($)
De-energization Class Action
Loss Contingencies [Line Items]
Litigation settlement, amount awarded from other party	$ 10

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WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) - Pacific Gas & Electric Co (Utility) - Complaints Brought By Butte County District Attorney - Loss from Wildfires	Mar. 17, 2020 count
Loss Contingencies [Line Items]
Number of guilty involuntary manslaughter pleas	84
Number of count related to unlawfully causing a fire (count)	1

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WILDFIRE- RELATED CONTINGENCIES (Restructuring Support Agreement) (Details) - USD ($) $ in Millions	Jan. 18, 2022	Jan. 15, 2021	Jul. 01, 2020	Jun. 12, 2020
Loss Contingencies [Line Items]
Payment of plan of reorganization, tax benefits payment agreement		$ 758
Fire Victim Trust
Loss Contingencies [Line Items]
Cash contribution by company			$ 5,400
Percentage of common stock owned, Fire Victim Trust if common issues additional shares				22.19%
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Plan of reorganization, future tax benefits payment agreement			$ 1,350
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2022 | Subsequent Event
Loss Contingencies [Line Items]
Cash	$ 592

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OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Apr. 20, 2020	Dec. 17, 2019
Loss Contingencies [Line Items]
Expenses and capital expenditures, disallowed costs	$ 1,625
Expenses and capital expenditures, disallowed capital, approved		$ 198
Shareholder-funded system enhancement initiatives, approved		64
Fine payable to general fund, suspended		$ 200
Wildfire mitigation plan memorandum account
Loss Contingencies [Line Items]
Expenses and capital expenditures, disallowed capital, approved	198
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Expenses and capital expenditures	1,625
Pacific Gas & Electric Co (Utility) | Pending Litigation | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Expenses and capital expenditures	$ 1,625
Shareholder-funded system enhancement initiatives, amount			$ 50

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OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Legal Obligation) (Details) - Pacific Gas & Electric Co (Utility) $ in Millions	Dec. 31, 2021 USD ($)
Loss Contingencies [Line Items]
Expense	$ 1,222
Capital	403
Total	1,625
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)
Loss Contingencies [Line Items]
Expense	236
Capital	0
Total	236
Transmission Safety Inspections and Repairs Expense (TO)
Loss Contingencies [Line Items]
Expense	433
Capital	0
Total	433
Vegetation Management Support Costs (FHPMA)
Loss Contingencies [Line Items]
Expense	36
Capital	0
Total	36
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)
Loss Contingencies [Line Items]
Expense	82
Capital	66
Total	148
2018 Camp Fire CEMA Expense (CEMA)
Loss Contingencies [Line Items]
Expense	435
Capital	0
Total	435
2018 Camp Fire CEMA Capital for Restoration (CEMA)
Loss Contingencies [Line Items]
Expense	0
Capital	253
Total	253
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)
Loss Contingencies [Line Items]
Expense	0
Capital	84
Total	$ 84

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OTHER CONTINGENCIES AND COMMITMENTS (Transmission Owner Rate) (Details) - USD ($) $ in Millions	Sep. 21, 2018	Dec. 31, 2021
Transmission Owner Rate Case Revenue
Loss Contingencies [Line Items]
Regulatory liabilities		$ 324
Regulatory assets		$ 197
Pacific Gas & Electric Co (Utility) | Electric
Loss Contingencies [Line Items]
Requested revenue rate	98.85%

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OTHER CONTINGENCIES AND COMMITMENTS (Interim Rate Relief Subject to Refund) (Details) $ in Millions	Sep. 21, 2021 USD ($)	Dec. 31, 2021 USD ($)	Nov. 02, 2021 USD ($)	Oct. 23, 2020 USD ($)	Sep. 30, 2020 USD ($)	Aug. 07, 2019 USD ($)	Apr. 25, 2019 USD ($)	Mar. 30, 2018 USD ($) catastrophicEvent
Loss Contingencies [Line Items]
Expenses and capital expenditures, disallowed costs		$ 1,625
CEMA Interim Rate Relief
Loss Contingencies [Line Items]
Cost recovery		373	$ 683			$ 763	$ 373
CEMA Interim Rate Relief | Mid 2016 - Early 2017
Loss Contingencies [Line Items]
Cost recovery								$ 183
Number of catastrophic events | catastrophicEvent								7
CEMA Interim Rate Relief | 2016 to 2017
Loss Contingencies [Line Items]
Cost recovery								$ 405
WMCE Interim Rate Relief
Loss Contingencies [Line Items]
Expenses and capital expenditures, disallowed costs					$ 1,180
Expenses and capital expenditures, capital expenditures					801
Cost recovery, increase to revenue requirement					$ 1,280
Capital expenditures for future recovery				$ 447
Interim revenue requirement	$ 447
Amortization period	17 months
Additional revenue requirement	$ 591
Additional amortization period	24 months
WMCE Interim Rate Relief | Fire hazard prevention memorandum account
Loss Contingencies [Line Items]
Cost recovery		293
WMCE Interim Rate Relief | Fire risk and wildfire mitigation memorandum account
Loss Contingencies [Line Items]
Cost recovery		740
WMCE Interim Rate Relief | Catastrophic event memorandum account
Loss Contingencies [Line Items]
Cost recovery		$ 251

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OTHER CONTINGENCIES AND COMMITMENTS (2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit) (Details) - Disallowance of Plant Costs - USD ($) $ in Millions	Jul. 07, 2021	Jun. 23, 2016	Jul. 31, 2020
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance		$ 696.0
Permanently disallowed capital		120.0
Amount subject to audit		$ 576.0
Capital expenditures for future recovery			$ 512.0
Loss Contingency Nature, Period One
Loss Contingencies [Line Items]
Capital expenditures for future recovery, seeking recovery			$ 416.3
Capital expenditures for future recovery, pending authorization	$ 356.3
Loss Contingency Nature, Period Two
Loss Contingencies [Line Items]
Capital expenditures for future recovery, pending authorization	$ 313.3
Capital expenditures for future recovery, pending authorization, amortization period	60 months
Loss Contingency Nature, Period Three
Loss Contingencies [Line Items]
Capital expenditures for future recovery, pending authorization	$ 43.0
Capital expenditures for future recovery, pending authorization, amortization period	12 months

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OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Accrued legal liabilities	$ 77	$ 144

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OTHER CONTINGENCIES AND COMMITMENTS (PSPS Class Action) (Details) $ in Billions	Dec. 19, 2019 USD ($)
PSPS Class Action | Pending Litigation | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Loss contingency, damages sought	$ 2.5

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract]
Topock natural gas compressor station	$ 299	$ 303
Hinkley natural gas compressor station	123	132
Former manufactured gas plant sites owned by the Utility or third parties	667	659
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	104	111
Fossil fuel-fired generation facilities and sites	70	96
Total environmental remediation liability	$ 1,263	$ 1,301

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OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 982
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 220
Topock Site | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Hinkley Natural Gas Compressor Station
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 138
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 477
Former Manufactured Gas Plant | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 50
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Fossil Fuel Fired Generation
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 43

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OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details)	12 Months Ended
	Dec. 31, 2021 USD ($) nuclear_generating_unit
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Maximum total payment incurred per event under the loss sharing program	$ 450,000,000
Nuclear Electric Insurance Limited and European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Insurance coverage, loss	400,000,000
Humboldt Bay Unit
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	50,000,000
Amount of liability insurance for Humboldt Bay Unit 3	53,000,000
Diablo Canyon
Long-term Purchase Commitment [Line Items]
Maximum public liability per nuclear incident under Price-Anderson Act	13,600,000,000
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	450,000,000
Maximum annual payment incurred per event under the loss sharing program	275,000,000
Coverage for purchased public liability insurance, per incident	$ 41,000,000
Period for inflation adjustment	5 years
Nuclear Incident
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	$ 3,200,000,000
Nuclear Incident | Humboldt Bay Unit
Long-term Purchase Commitment [Line Items]
Amount of indemnification from the nuclear regulatory commission for public liability arising from nuclear incidents	500,000,000
Non-Nuclear Incident
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	2,700,000,000
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Full insurance policy limit	200,000,000
Potential premium obligation	4,000,000
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Potential premium obligation	$ 42,000,000

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Long-term Purchase Commitment [Line Items]
2022	$ 3,518
2023	2,761
2024	2,547
2025	2,443
2026	2,313
Thereafter	19,920
Total purchase commitments	33,502
Renewable Energy
Long-term Purchase Commitment [Line Items]
2022	2,062
2023	2,043
2024	2,020
2025	2,009
2026	1,948
Thereafter	19,310
Total purchase commitments	29,392
Conventional Energy
Long-term Purchase Commitment [Line Items]
2022	530
2023	425
2024	282
2025	216
2026	204
Thereafter	539
Total purchase commitments	2,196
Other
Long-term Purchase Commitment [Line Items]
2022	61
2023	61
2024	61
2025	61
2026	21
Thereafter	19
Total purchase commitments	284
Natural Gas
Long-term Purchase Commitment [Line Items]
2022	823
2023	191
2024	157
2025	157
2026	140
Thereafter	52
Total purchase commitments	1,520
Nuclear Fuel
Long-term Purchase Commitment [Line Items]
2022	42
2023	41
2024	27
2025	0
2026	0
Thereafter	0
Total purchase commitments	$ 110

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OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Power Purchases and Electric Capacity
Third-Party Power Purchase Agreements [Line Items]
Costs incurred for power purchases and electric capacity	$ 3,000	$ 2,900	$ 3,000
Nuclear Fuel
Third-Party Power Purchase Agreements [Line Items]
Payments for nuclear fuel	79	111	74
Gas Contracts
Third-Party Power Purchase Agreements [Line Items]
Cost of goods	$ 1,200	$ 800	$ 900

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details) $ in Millions	Dec. 31, 2021 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2022	$ 43
2023	65
2024	81
2025	77
2026	74
Thereafter	2,938
Total minimum lease payments	$ 3,278

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OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Leased Assets [Line Items]
Payments for other commitments	$ 50	$ 45	$ 48
Minimum
Operating Leased Assets [Line Items]
Extension option for operating leases	1 year
Maximum
Operating Leased Assets [Line Items]
Extension option for operating leases	5 years

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OTHER CONTINGENCIES AND COMMITMENTS (Oakland Headquarters Lease) (Details) ft² in Thousands, $ in Millions	Oct. 23, 2020 USD ($)	Jun. 05, 2020 USD ($) ft²
Commitments and Contingencies Disclosure [Abstract]
Rentable square feet | ft²		910
Lease, option payment letter of credit	$ 75
Lease, security letter of credit	$ 75
Term of contract		34 years 11 months
Purchase options, land, value		$ 892

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating expenses	$ (18,759)	$ (16,714)	$ (27,223)
Interest income	20	39	82
Interest expense	(1,601)	(1,260)	(934)
Other income, net	457	483	250
Reorganization items, net	(11)	(1,959)	(346)
Income tax provision (benefit)	836	362	(3,400)
Loss Attributable to Common Shareholders	(102)	(1,318)	(7,656)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations	7	(17)	(1)
Total other comprehensive income (loss)	$ 7	$ (17)	$ (1)
Weighted Average Common Shares Outstanding, Basic (in shares)	1,985,000,000	1,257,000,000	528,000,000
Weighted Average Common Shares Outstanding, Diluted (in shares)	1,985,000,000	1,257,000,000	528,000,000
Net Loss Per Common Share, Basic (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)
Net Loss Per Common Share, Diluted (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)
Pension and other postretirement benefit plans obligations, tax	$ 3	$ 7	$ 0
Treasury stock, shares at cost (in shares)	477,743,590	0
PG&E Corporation
Operating expenses	$ (124)	$ (103)	(114)
Interest income	0	0	1
Interest expense	(230)	(149)	(21)
Other income, net	(54)	13	10
Reorganization items, net	1	(1,649)	(26)
Equity in earnings of subsidiaries	137	411	(7,622)
Income (Loss) Before Income Taxes	(152)	(1,350)	(7,634)
Income tax provision (benefit)	(64)	(46)	8
Loss Attributable to Common Shareholders	(88)	(1,304)	(7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations	7	(17)	(1)
Total other comprehensive income (loss)	7	(17)	(1)
Comprehensive Loss	$ (81)	$ (1,321)	$ (7,643)
Weighted Average Common Shares Outstanding, Basic (in shares)	2,463,000,000	1,257,000,000	528,000,000
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,463,000,000	1,257,000,000	528,000,000
Net Loss Per Common Share, Basic (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)
Net Loss Per Common Share, Diluted (in dollars per share)	$ (0.05)	$ (1.05)	$ (14.50)
Pension and other postretirement benefit plans obligations, tax	$ 3	$ 7	$ 0
PG&E Corporation | Administrative service revenue
Revenue	$ 118	$ 127	$ 138

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 291	$ 484	$ 1,570
Other	882	1,334
Total current assets	11,077	9,602
Noncurrent Assets
Equipment	98,960	93,894
Accumulated depreciation	(29,134)	(27,758)
Net property, plant, and equipment	69,826	66,136
Operating lease right of use asset	1,234	1,741
TOTAL ASSETS	103,327	97,856
Current Liabilities
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481	28
Operating lease liabilities	468	533
Other current liabilities	2,436	2,256
Total current liabilities	17,427	13,581
Noncurrent Liabilities
Debtor-in-possession financing	38,225	37,288
Operating lease liabilities	810	1,208
Other	4,308	3,848
Total noncurrent liabilities	64,677	63,022
Common Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,985,400,540 and 1,984,678,673 shares outstanding at respective dates	35,129	30,224
Reinvested earnings	(9,284)	(9,196)
Accumulated other comprehensive loss	(20)	(27)
Total shareholders' equity	20,971	21,001
TOTAL LIABILITIES AND EQUITY	103,327	97,856
PG&E Corporation
Current Assets
Cash and cash equivalents	126	223
Advances to affiliates	21	48
Income taxes receivable	10	12
Other	12	13
Total current assets	169	296
Noncurrent Assets
Equipment	2	2
Accumulated depreciation	(2)	(2)
Net property, plant, and equipment	0	0
Investments in subsidiaries	30,232	25,244
Other investments	181	186
Operating lease right of use asset	0	3
Deferred income taxes	297	237
Total noncurrent assets	30,710	25,670
TOTAL ASSETS	30,879	25,966
Current Liabilities
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	27	28
Accounts payable – other	200	49
Operating lease liabilities	0	3
Other current liabilities	69	72
Total current liabilities	296	152
Noncurrent Liabilities
Debtor-in-possession financing	4,592	4,624
Operating lease liabilities	0	0
Other	168	191
Total noncurrent liabilities	4,760	4,815
Common Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,985,400,540 and 1,984,678,673 shares outstanding at respective dates	35,129	30,224
Reinvested earnings	(9,286)	(9,198)
Accumulated other comprehensive loss	(20)	(27)
Total shareholders' equity	25,823	20,999
TOTAL LIABILITIES AND EQUITY	$ 30,879	$ 25,966

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($) $ in Millions		12 Months Ended
	Aug. 11, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities
Net Loss		$ (88)	$ (1,304)	$ (7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and tax credits, net		1,783	1,097	(2,948)
Reorganization items, net (Note 2)		(73)	1,458	108
Liabilities subject to compromise		0	413	12,222
Net cash provided by (used in) operating activities		2,262	(19,130)	4,816
Cash Flows from Investing Activities
Net cash used in investing activities		(6,905)	(7,748)	(6,378)
Cash Flows From Financing Activities:
Debtor-in-possession credit facility debt issuance costs		0	(6)	(113)
Bridge facility financing fees		0	(73)	0
Repayment of long-term debt		(87)	(764)	0
Intercompany note to PG&E Corporation	$ (145)
Equity Units issued		0	1,304	0
Other		(29)	(40)	(8)
Net cash provided by financing activities		4,323	25,928	1,464
Net change in cash, cash equivalents, and restricted cash		(320)	(950)	(98)
Cash, cash equivalents, and restricted cash at January 1		627	1,577	1,675
Cash, cash equivalents, and restricted cash at December 31		307	627	1,577
Cash paid for:
Interest, net of amounts capitalized		(1,404)	(1,563)	(10)
Income taxes, net		99	0	0
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets		100	13	2,816
Common stock issued in satisfaction of liabilities		0	8,276	0
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement		(4,854)	0	0
Pacific Gas & Electric Co (Utility)
Cash Flows from Operating Activities
Net Loss		138	411	(7,622)
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and tax credits, net		1,846	1,141	(2,952)
Reorganization items, net (Note 2)		(41)	(90)	97
Liabilities subject to compromise		0	401	12,194
Net cash provided by (used in) operating activities		2,448	(19,047)	4,810
Cash Flows from Investing Activities
Net cash used in investing activities		(7,050)	(7,748)	(6,378)
Cash Flows From Financing Activities:
Debtor-in-possession credit facility debt issuance costs		0	(6)	(97)
Bridge facility financing fees		0	(33)	0
Repayment of long-term debt		(59)	(100)	0
Intercompany note to PG&E Corporation		(145)	0	0
Other		(1)	(42)	(8)
Net cash provided by financing activities		4,379	26,070	1,395
Net change in cash, cash equivalents, and restricted cash		(223)	(725)	(173)
Cash, cash equivalents, and restricted cash at January 1		404	1,129	1,302
Cash, cash equivalents, and restricted cash at December 31		181	404	1,129
Cash paid for:
Interest, net of amounts capitalized		(1,198)	(1,458)	(7)
Income taxes, net		99	0	0
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets		100	13	2,807
PG&E Corporation
Cash Flows from Operating Activities
Net Loss		(88)	(1,304)	(7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization		51	28	43
Equity in earnings (loss) of subsidiaries		(139)	(412)	7,622
Deferred income taxes and tax credits, net		(60)	(50)	0
Reorganization items, net (Note 2)		(32)	1,548	11
Current income taxes receivable/payable		2	0	6
Liabilities subject to compromise		0	12	28
Other		81	97	(62)
Net cash provided by (used in) operating activities		(185)	(81)	6
Cash Flows from Investing Activities
Investment in subsidiaries		0	(12,986)	0
Net cash used in investing activities		0	(12,986)	0
Cash Flows From Financing Activities:
Debtor-in-possession credit facility debt issuance costs		0	0	(16)
Bridge facility financing fees		0	(40)	0
Proceeds from issuance of long-term debt		0	4,660	0
Repayment of long-term debt		(28)	(664)	0
Intercompany note to PG&E Corporation		145	0	0
Common stock issued		0	7,582	85
Equity Units issued		0	1,304	0
Other		(29)	0	0
Net cash provided by financing activities		88	12,842	69
Net change in cash, cash equivalents, and restricted cash		(97)	(225)	75
Cash, cash equivalents, and restricted cash at January 1		223	448	373
Cash, cash equivalents, and restricted cash at December 31		126	223	448
Cash paid for:
Interest, net of amounts capitalized		(207)	(105)	(3)
Income taxes, net		1	0	0
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets		0	0	9
Common stock issued in satisfaction of liabilities		0	8,276	0
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement		$ 4,854	$ 0	$ 0

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SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 146	$ 43	$ 56
Charged to Costs and Expenses	136	138	0
Charged to Other Accounts	0	0	0
Deductions	111	35	13
Balance at End of Period	$ 171	$ 146	$ 43