UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549
					FORM	10-Q
(Mark One)
☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the quarterly period ended				March 31, 2023
			OR
☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission File Number				Exact Name of Registrant as Specified in its Charter			State or Other Jurisdiction of Incorporation				IRS Employer Identification Number
1-12609				PG&E Corporation			California				94-3234914
1-2348				Pacific Gas and Electric Company			California				94-0742640
PG&E Corporation							Pacific Gas and Electric Company
300 Lakeside Drive							300 Lakeside Drive
Oakland,		California	94612				Oakland,		California	94612
Address of principal executive offices, including zip code
PG&E Corporation							Pacific Gas and Electric Company
415	973-1000						415	973-7000
Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, no par value	PCG	The New York Stock Exchange
Equity Units	PCGU	The New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 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
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, 5% series A redeemable	PCG-PE	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% redeemable	PCG-PI	NYSE American LLC

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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, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation:	☒	Large accelerated filer	☐	Accelerated filer
	☐	Non-accelerated filer
	☐	Smaller reporting company	☐	Emerging growth company
Pacific Gas and Electric Company:	☐	Large accelerated filer	☐	Accelerated filer
	☒	Non-accelerated filer
	☐	Smaller reporting company	☐	Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
PG&E Corporation:			☐
Pacific Gas and Electric Company:			☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:			☐	Yes	☒	No
Pacific Gas and Electric Company:			☐	Yes	☒	No
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
PG&E Corporation:			☒	Yes	☐	No
Pacific Gas and Electric Company:			☒	Yes	☐	No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common stock outstanding as of April 26, 2023:
PG&E Corporation:	2,473,521,996*
Pacific Gas and Electric Company:	264,374,809
*Includes 127,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 350,000,000 shares of common stock held by Pacific Gas and Electric Company.

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PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2023

TABLE OF CONTENTS

		SEC Form 10-Q Reference Number
UNITS OF MEASUREMENT
GLOSSARY
FORWARD-LOOKING STATEMENTS
RISK FACTORS		Part II, Item 1A
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		Part I, Item 2
	OVERVIEW
	RESULTS OF OPERATIONS
	LIQUIDITY AND FINANCIAL RESOURCES
	LITIGATION MATTERS
	REGULATORY MATTERS
	LEGISLATIVE AND REGULATORY INITIATIVES
	ENVIRONMENTAL MATTERS
	RISK MANAGEMENT ACTIVITIES
	CRITICAL ACCOUNTING ESTIMATES
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS		Part I, Item 1
	PG&E CORPORATION
	CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	CONDENSED CONSOLIDATED BALANCE SHEETS
	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
	PACIFIC GAS AND ELECTRIC COMPANY
	CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	CONDENSED CONSOLIDATED BALANCE SHEETS
	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
	NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
	NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
	NOTE 4: DEBT
	NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
	NOTE 6: EQUITY
	NOTE 7: EARNINGS PER SHARE
	NOTE 8: DERIVATIVES
	NOTE 9: FAIR VALUE MEASUREMENTS
	NOTE 10: WILDFIRE-RELATED CONTINGENCIES
	NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		Part I, Item 3
CONTROLS AND PROCEDURES		Part I, Item 4
LEGAL PROCEEDINGS		Part II, Item 1
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		Part II, Item 2

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EXHIBITS	Part II, Item 6
SIGNATURES

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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.

2022 Form 10-K	PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2022
Form 10-Q	PG&E Corporation’s and the Utility’s joint Quarterly Report on Form 10-Q for the period ended March 31, 2023
AB	Assembly Bill
ALJ	administrative law judge
Amended Articles	Amended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020, and for PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022
ARO	asset retirement obligation
Bankruptcy Court	the U.S. Bankruptcy Court for the Northern District of California
CAISO	California Independent System Operator Corporation
Cal Fire	California Department of Forestry and Fire Protection
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
CPPMA	COVID-19 Pandemic Protections Memorandum Account
CPUC	California Public Utilities Commission
CRR	congestion revenue rights
D&O Insurance	directors and officers liability insurance
Diablo Canyon	Diablo Canyon nuclear power plant
District Court	United States District Court for the Northern District of California
DOE	United States Department of Energy
DOJ	United States Department of Justice
DTSC	California Department of Toxic Substances Control
DWR	California Department of Water Resources
EMANI	European Mutual Association for Nuclear Insurance
Emergence Date	July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOEP	Enhanced Oversight and Enforcement Process
EPS	earnings per common share
EPSS	Enhanced Powerline Safety Settings
Exchange Act	Securities Exchange Act of 1934, as amended
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
First Mortgage Bonds	bonds issued pursuant to the Indenture of Mortgage, dated as of June 19, 2020, between the Utility and The Bank of New York Mellon Trust Company, N.A., as amended and supplemented
FRMMA	Fire Risk Mitigation Memorandum Account
GAAP	U.S. Generally Accepted Accounting Principles
GO	general order
GRC	general rate case
GT&S	gas transmission and storage

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HSMA	Hazardous Substance Memorandum Account
IRC	Internal Revenue Code
IOUs	investor-owned utility(ies)
Lakeside Building	300 Lakeside Drive, Oakland, California, 94612
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part I, Item 2, of this Form 10-Q
MGP	manufactured gas plants
NAV	net asset value
NEIL	Nuclear Electric Insurance Limited
New Shares	Shares of PG&E Corporation common stock held by ShareCo that may be exchanged for Plan Shares as contemplated by the Share Exchange and Tax Matters Agreement
NRC	Nuclear Regulatory Commission
OEIS	Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OII	order instituting investigation
Pacific Generation	Pacific Generation LLC, a subsidiary of the Utility
PERA	Public Employees Retirement Association of New Mexico
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
Plan Shares	Shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan
PSPS	Public Safety Power Shutoff
Receivables Securitization Program	The accounts receivable securitization program entered into by the Utility on October 5, 2020, providing for the sale of a portion of the Utility's accounts receivable and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions
ROE	return on equity
RTBA	Risk Transfer Balancing Account
RUBA	Residential Uncollectibles Balancing Account
SB	Senate Bill
SEC	United States Securities and Exchange Commission
Securities Act	The Securities Act of 1933, as amended
SED	Safety and Enforcement Division of the CPUC
SFGO	The Utility’s former San Francisco General Office headquarters complex
Share Exchange and Tax Matters Agreement	Share Exchange and Tax Matters Agreement dated July 8, 2021 between PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust
ShareCo	PG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV	PG&E AR Facility, LLC
TCJA	Tax Cuts and Jobs Act of 2017
TO	transmission owner
USFS	United States Forest Service
Utility	Pacific Gas and Electric Company
Utility Revolving Credit Agreement	Credit Agreement, dated as of July 1, 2020, as amended, by and among the Utility, the several banks and other financial institutions or entities party thereto from time to time and Citibank, N.A., as Administrative Agent and Designated Agent
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
WMBA	Wildfire Mitigation Balancing Account

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

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines associated with various investigations and proceedings; forecasts of capital expenditures; 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,” “commit,” “goal,” “target,” “will,” “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 prudency standard under AB 1054 effectively mitigate 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;

•the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service area, 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”), the wildfire that began on September 6, 2022 near OxBow Reservoir in Placer County, California (the “2022 Mosquito 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; the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire; 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 the Wildfire Fund or other third parties 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; or to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; the cost of the program and the timing and outcome of any proceeding to recover such costs through rates; and any determination by OEIS that the Utility has not complied with its WMP;

•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;

•significant changes to the electric power and gas industries driven by technological advancements, electrification, and the transition to a decarbonized economy; the impact of reductions in Utility customer demand for electricity and natural gas, driven by customer departures to community choice aggregators, direct access providers, and legislative mandates to replace gas-fuel technologies; 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;

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•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, litigation, 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, mitigate, 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;

•existing and 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 greenhouse gas emissions, renewable energy targets, energy efficiency standards, distributed energy resources, and electric vehicles;

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

◦the regulation of utilities and their affiliates, including the conditions that apply to PG&E Corporation as the Utility’s holding company;

◦privacy and cyber security; 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; the Utility’s application to transfer its non-nuclear generation assets to Pacific Generation and the potential sale of a minority interest in Pacific Generation; and the transfer of ownership of the Utility’s assets to municipalities or other public entities, including as a result of the City and County of San Francisco’s valuation petition;

•whether the Utility can control its operating costs within the authorized levels of spending; whether the Utility can continue implementing the Lean operating system and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; the risks and uncertainties associated with inflation; 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;

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•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 cyber security protections; environmental laws and regulations; or otherwise, such as fines; penalties; remediation obligations; 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 resolution of the Subordinated Claims and 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; the Wildfire-Related Non-Bankruptcy Claims; 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 the remaining $1.385 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility;

•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;

•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 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 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 workforce availability and the ability of the Utility to collect on customer receivables; 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 in the 2022 Form 10-K and a detailed discussion of these matters contained in Item 7. MD&A in the 2022 Form 10-K and Item 2. in this Form 10-Q. 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, including regarding dividends, at http://investor.pgecorp.com, under the “Wildfire and Safety Updates,” “News & Events: Events & Presentations,” and “Shareholders: Dividend Information” 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 to the CPUC. 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.

ITEM 1A. RISK FACTORS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see the section of the 2022 Form 10-K entitled “Risk Factors” and the section of this quarterly report entitled “Forward-Looking Statements.”

PART I. FINANCIAL INFORMATION

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

OVERVIEW

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Item 1. It should also be read in conjunction with the 2022 Form 10-K.

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 Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, the Wildfire Fund, and regulatory recovery.

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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 Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening. In particular, in 2022, the Utility expanded the EPSS program to all distribution lines in high fire risk areas. The Utility is also focused on undergrounding more lines each year while using economies of scale to make undergrounding more cost efficient. These initiatives have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.

PG&E Corporation and the Utility have incurred and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. If additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on the costs of the Utility’s wildfire mitigation initiatives.

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 continually reviews 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 late inspections or other noncompliance related to wildfire mitigation efforts. See “Self-Reports to the CPUC” in “Regulatory Matters” below.

Despite these extensive measures, 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. Once an ignition has occurred, the Utility is unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.

The financial impact of past wildfires is significant. As of March 31, 2023, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.025 billion, $400 million, $1.175 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries. 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.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 31 counts in connection with the 2020 Zogg fire, of which the court has dismissed 20 counts. If the Utility were to be convicted of any of the remaining charges, the Utility could be subject to material fines, penalties, and restitution, as well as non-monetary remedies such as oversight requirements. Accordingly, depending on which charges the Utility were to be convicted of, its total losses associated with the 2020 Zogg fire could materially exceed the $400 million of aggregate liability that PG&E Corporation and the Utility have recorded.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage through the Wildfire Fund, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. See “Loss Recoveries” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. As of March 31, 2023, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $371 million for the 2020 Zogg fire, $529 million for the 2021 Dixie fire, and $49 million for the 2022 Mosquito fire. Additionally, the Utility does not expect that any of its liability insurance would cover restitution payments, if such payments were ordered by the court presiding over the criminal proceeding in connection with the 2020 Zogg fire.

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If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires, 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. 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, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. As of March 31, 2023, the Utility has recorded a Wildfire Fund receivable of $175 million for the 2021 Dixie fire. See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

The Utility will be permitted to recover its wildfire-related claims and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as receivables. As of March 31, 2023, the Utility has recorded receivables for regulatory recovery of $514 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information.

•The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. 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, administrative 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” below), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded in memorandum and balancing accounts has increased. The Utility has also applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. 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 3 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.

•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility is subject to enforcement, litigation, and regulatory matters, including those described above, the Safety Culture OII, EOEP proceedings, and actions in connection with the Utility’s WMP, and safety and other self-reports. See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1. In addition, the Utility’s business profile and financial results could be impacted by actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions or by state intervention, including the possibility of a state takeover of the Utility. See “Jurisdictions may attempt to acquire the Utility’s assets through eminent domain” in Item 1A . Risk Factors in the 2022 Form 10-K for more information. These matters could result in penalties, additional regulatory requirements, or changes to the Utility’s operations. PG&E Corporation and the Utility seek to limit these matters by implementing a robust compliance program and by delivering excellent customer experiences.

•PG&E Corporation’s and the Utility’s Ability to Control Operating Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also reducing non-fuel Operating and maintenance costs by two percent per year. The Utility’s ability to meet this goal depends, in part, on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system.

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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 the 2022 Form 10-K.  In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See “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 $26.6 billion and a California net operating loss carryforward of approximately $25.2 billion as of December 31, 2022.

Under Section 382 of the IRC, 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 IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding deferred tax asset 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. On each of January 9, 2023 and April 11, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the three months ended March 31, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 60,000,000 shares resulted in an aggregate tax benefit of $256 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Cumulatively through March 31, 2023, the Fire Victim Trust has sold 290,000,000 shares resulting in an aggregate tax benefit of $1.1 billion recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

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 2,473,521,996 shares outstanding as of April 26, 2023, only 1,868,034,816 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 taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of April 26, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of April 26, 2023 was 3.58% of the outstanding shares. As of April 26, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 350,000,000 shares of PG&E Corporation common stock in the aggregate.

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RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three months ended March 31, 2023 and 2022. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) attributable to common shareholders for the three months ended March 31, 2023 and 2022:

	Three Months Ended March 31,
(in millions)	2023		2022
Consolidated Total	$	569	$	475
PG&E Corporation	(54)		(52)
Utility	$	623	$	527

PG&E Corporation’s net loss primarily consists of interest expense on long-term debt.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three months ended March 31, 2023 and 2022.  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. 

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.

CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results.

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	Three Months Ended March 31, 2023						Three Months Ended March 31, 2022
	Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	3,062	$	1,057	$	4,119	$	2,904	$	1,254	$	4,158
Natural gas operating revenues	982		1,108		2,090		922		718		1,640
Total operating revenues	4,044		2,165		6,209		3,826		1,972		5,798
Cost of electricity	—		522		522		—		502		502
Cost of natural gas	—		916		916		—		561		561
Operating and maintenance	1,921		753		2,674		2,085		1,022		3,107
SB 901 securitization charges, net	273		—		273		—		—		—
Wildfire-related claims, net of recoveries	(2)		—		(2)		(1)		—		(1)
Wildfire Fund expense	117		—		117		118		—		118
Depreciation, amortization, and decommissioning	1,077		—		1,077		972		—		972
Total operating expenses	3,386		2,191		5,577		3,174		2,085		5,259
Operating income (loss)	658		(26)		632		652		(113)		539
Interest income	110		—		110		9				9
Interest expense	(520)		—		(520)		(364)		—		(364)
Other income, net	58		26		84		43		113		156
Income before income taxes	306		—		306		340		—		340
Income tax benefit (1)					(320)						(190)
Net income					626						530
Preferred stock dividend requirement (1)					3						3
Income Available for Common Shareholders					$	623					$	527

(1) These items impacted earnings for the three months ended March 31, 2023 and 2022.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three months ended March 31, 2023 and 2022, 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 $218 million, or 6%, in the three months ended March 31, 2023, compared to the same period in 2022, primarily due to the recognition of approximately $585 million in revenues authorized in the final decision of the 2020 WMCE application (see “2020 WMCE Application” below) in the three months ended March 31, 2023, with no comparable revenues in 2022. This increase was partially offset by the recognition of approximately $310 million in revenues related to the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K) in the three months ended March 31, 2022 with no comparable revenues in 2023.

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Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings decreased by $164 million, or 8%, in the three months ended March 31, 2023, compared to the same period in 2022, as a result of labor redeployment due to winter storm response priorities which are generally recoverable through CEMA, and the recognition of approximately $310 million of previously deferred expenses which were authorized by the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K) in the three months ended March 31, 2022, with no comparable costs in the same period in 2023. Additionally, the Utility recognized approximately $85 million in expenses related to the Kincade SED Settlement as well as approximately $55 million in expenses related to the Kincade Stipulation and the Dixie Stipulation (each as defined in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K) in the three months ended March 31, 2022 with no comparable charges in 2023. These decreases were partially offset by the recognition of approximately $422 million of previously deferred expenses authorized in the final decision of the 2020 WMCE application (see “2020 WMCE Application” below) in the three months ended March 31, 2023, with no comparable costs in 2022.

SB 901 Securitization Charges, Net

SB 901 securitization charges, net, that impacted earnings increased by $273 million, or 100%, in the three months ended March 31, 2023, compared to the same period in 2022. In the first quarter of 2023, the Utility recorded charges of $273 million representing the amount that is refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock, with no comparable charges in 2022. For more information, see Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Wildfire-Related Claims, Net of Recoveries

There was no material change to Wildfire-Related Claims, Net of Recoveries that impacted earnings for the periods presented.

Wildfire Fund Expense

There was no material change to Wildfire Fund expense that impacted earnings for the periods presented.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by $105 million, or 11%, in the three months ended March 31, 2023, compared to the same period in 2022, primarily due to capital additions.

Interest Income

Interest income that impacted earnings increased by $101 million, or 100%, in the three months ended March 31, 2023, compared to the same period in 2022, primarily due to higher interest rates earned on regulatory balancing accounts.

Interest Expense

Interest expense that impacted earnings increased by $156 million, or 43%, in the three months ended March 31, 2023 compared to the same period in 2022, primarily due to the issuance of additional long-term debt and an increase in interest rates on variable-rate debt.

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 the equity component of allowance for funds used during construction, and gains and losses on equity securities held by the customer credit trust.

Income Tax Benefit

Income tax benefit increased by $130 million, or 68%, in the three months ended March 31, 2023, compared to the same period in 2022, primarily due to an increase in the tax benefit recognized related to the sale of shares in the Fire Victim Trust in the three months ended March 31, 2023, as compared to the same period in 2022.

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

	Three Months Ended March 31,
	2023		2022
Federal statutory income tax rate	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(26.7)	%	(11.5)	%
Effect of regulatory treatment of fixed asset differences (2)	(35.6)	%	(30.0)	%
Tax credits	(0.8)	%	(0.9)	%
Fire Victim Trust (3)	(63.0)	%	(29.8)	%
Other, net	0.2	%	(4.5)	%
Effective tax rate	(104.9)	%	(55.7)	%

(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, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes 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. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA.

(3) Includes the tax benefit related to the sale of shares of stock in the Fire Victim Trust. See “Tax Matters” above and Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. 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. The cost of electricity increased in three months ended March 31, 2023 as compared to the same period in 2022. This increase was primarily the result of higher fuel prices for certain generation facilities due to increased system demand for natural gas and tighter supplies experienced during below-normal temperatures occurring during the period, partially offset by decreased customer demand for the Utility’s bundled electric services and higher energy sales to the CAISO.

	Three Months Ended March 31,
(in millions)	2023		2022
Cost of purchased power, net	$	140	$	434
Fuel used in generation facilities	382		68
Total cost of electricity	$	522	$	502

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Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The cost of natural gas increased in the three months ended March 31, 2023, as compared to the same period in 2022. Customer demand increased due to below-normal temperatures occurring during the period with more natural gas used for space heating and increased demand for natural-gas fired electric generation facilities due to lower availability of hydroelectric generation facilities and fewer electric imports. Natural gas prices increased as a result of higher demand, lower natural gas storage levels, and regional pipeline constraints.

	Three Months Ended March 31,
(in millions)	2023		2022
Cost of natural gas sold	$	877	$	522
Transportation cost of natural gas sold	39		39
Total cost of natural gas	$	916	$	561

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 on 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.

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The Utility’s annual cost of capital adjustment mechanism provides that in any year during the applicable cost of capital period in which the difference between (i) the average Moody’s Baa utility bond rates (as measured in the 12-month period from October of the prior year through September of the year in which the mechanism could trigger (the “Index”)) and (ii) 4.37% (based on the 2023 Cost of Capital decision) 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 is triggered, to become effective on January 1 of the next year. As of April 26, 2023, for the period since October 1, 2022, the Index averaged 134 basis points above the Utility’s cost of capital benchmark rate of 4.37%.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Arrearages Related to 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 outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus, 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. In particular, the Utility continues to experience increased arrearages. 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, an annual cap set by the CPUC on the number of service disconnections for residential customers, and the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections.” The Utility resumed non-residential and residential service disconnections as of October 13, 2022. The Utility’s accounts receivable balances over 30 days outstanding as of March 31, 2023 were approximately $1.1 billion, or $821 million higher than 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.

As of March 31, 2023, PG&E Corporation and the Utility had access to approximately $3.9 billion of total liquidity comprised of approximately $871 million of Utility cash, $157 million of PG&E Corporation cash and $2.8 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

The Utility established the CPPMA for tracking costs related to the CPUC’s emergency authorization and order for the period the CPPMA was in effect. As of March 31, 2023, costs recorded to the CPPMA totaled $27 million and were reflected in Long-term regulatory assets on the Condensed Consolidated Balance Sheets. In addition to the $27 million recorded to the CPPMA, the Utility recorded approximately $104 million of under-collections from residential customers from March 4, 2020 to March 31, 2023 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Condensed Consolidated Balance Sheets.

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, 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.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. 

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Financial Resources

Equity Financings

PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term and short-term debt. PG&E Corporation and the Utility are also pursuing the potential sale of a minority interest in Pacific Generation. (See “Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets” below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

Debt Financings

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.70% First Mortgage Bonds due 2053. The Utility intends to disburse or allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing eligible green projects and eligible social projects. Pending full disbursement or allocation, the proceeds were used for the repayment of a portion of the loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

Credit Facilities

As of March 31, 2023, PG&E Corporation and the Utility had $500 million and $2.3 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, 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.

On April 18, 2023, the Utility amended its existing term loan agreement to extend the maturity of the $125 million 364-day tranche loan thereunder from April 19, 2023 to April 16, 2024. The 364-day tranche loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375%, or (2) the alternative base rate plus an applicable margin of 0.375%.

For more information, see “Credit Facilities” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Dividends

On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023. On February 16, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on May 15, 2023, to holders of record on April 28, 2023.

On February 16, 2023, the Board of Directors of the Utility declared a common stock dividend of $425 million, which was paid to PG&E Corporation on February 28, 2023.

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On December 20, 2017, the Boards of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation’s common stock, beginning the fourth quarter of 2017. Subject to the dividend restrictions described in Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K, any decision to declare and pay dividends on PG&E Corporation’s common stock in the future will be made at the discretion of the Board of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions of PG&E Corporation, and other factors that the Board of Directors of PG&E Corporation may deem relevant. 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 as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

Utility Cash Flows

PG&E Corporation’s condensed consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the three months ended March 31, 2023 and 2022. 

The Utility’s cash flows were as follows:

	Three Months Ended March 31,
(in millions)	2023		2022
Net cash provided by operating activities	$	1,262	$	1,732
Net cash used in investing activities	(2,140)		(2,330)
Net cash provided by financing activities	1,314		645
Net change in cash, cash equivalents, and restricted cash	$	436	$	47

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During the three months ended March 31, 2023, net cash provided by operating activities decreased by $470 million compared to the same period in 2022. The decrease was primarily due to an increase in costs incurred for repair and restoration work performed related to an increase in declared winter storm events in the Utility’s service area during the first quarter of 2023.

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, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, including funds available from self-insurance (see “2023 General Rate Case” in the Regulatory Matters” section below for more information), 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 Litigation” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 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 area and the ability of the Utility to collect on its customer receivables;

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

•the timing and amount of costs in connection with the 2020-2022 and 2023-2025 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 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

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•the timing and outcomes of the Utility’s 2023 GRC and other 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 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

Investing Activities

Net cash used in investing activities decreased by $190 million during the three months ended March 31, 2023 as compared to the same period in 2022. The decrease was primarily due to a $169 million increase in customer credit trust investment sales.

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 and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit 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. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the SB 901 securitization is designed to be rate neutral to customers.

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 $7.9 billion and $11.2 billion of capital expenditures in 2023. Additionally, future cash flows used in investing activities could be impacted by the timing and amount related to the potential purchase of the Lakeside Building, and the timing and amount of contributions to the customer credit trust, including certain shareholder tax benefits, and $1.0 billion of cash to be contributed in 2024.

Financing Activities

Net cash provided by financing activities increased by $669 million during the three months ended March 31, 2023 as compared to the same period in 2022. The increase was primarily due to a $2.7 billion increase in borrowings under the Utility’s credit facilities. The increase was offset by a $1.6 billion increase in repayments under the Utility’s credit facilities and a common stock dividend payment of $425 million to PG&E Corporation on February 28, 2023.

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, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 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.

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.

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During the three months ended March 31, 2023 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters.

•On March 27, the Utility submitted its 2023-2025 WMP.

•On March 2, the NRC approved the Utility’s exemption request to allow continued operations at Diablo Canyon past the plant’s current licenses while the Utility’s license renewal application is under review.

•On February 2, the CPUC approved a final decision, adopting without modification the Utility’s settlement agreement in its 2020 WMCE proceeding, pursuant to which the Utility will recover a revenue requirement of $1.04 billion.

•On January 18, the Utility submitted a partial settlement regarding the 2021 WMCE application pursuant to which the Utility would receive a revenue requirement of $720.7 million.

•On January 12, the CPUC approved a settlement pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023.

•On January 6, the Utility filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the 2023 GRC proceeding, for $183 million in expense and $127 million of capital expenditures.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. 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 may also authorize 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. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of March 31, 2023, the Utility had recorded an aggregate amount of approximately $6.0 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and Microgrids Memorandum Account. Of these costs, approximately $518 million was authorized for recovery and accounted for as current, and $5.5 billion was accounted for as long term as of March 31, 2023. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” below.

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The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the three months ended March 31, 2023 are summarized in the following table:

Proceeding	Request	Status
2020 WMCE	Revenue requirement of approximately $1.28 billion	Settlement agreement to recover $1.04 billion of revenue requirement approved February 2023.
2021 WMCE	Revenue requirement of approximately $1.47 billion	Partial settlement agreement to recover $721 million of revenue requirement filed January 2023. Settlement excludes VMBA’s $591 million proposed revenue requirement.
2022 WMCE	Revenue requirement of approximately $1.36 billion	Filed December 15, 2022. Proposed decision authorizing $1.1 billion of interim rate relief issued April 2023.

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 excluded amounts disallowed as a result of the CPUC’s decision in the OII into 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”), and the 2018 Camp fire, consisted 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 were incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflected work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue included 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 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 authorizes the Utility to recover a revenue requirement of $591 million over a 24-month amortization period beginning March 2023, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On February 2, 2023, the CPUC approved a final decision adopting the settlement agreement without modifications.

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 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 memorandum 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 request of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction was a result of costs, such as employee business travel expenses and in-person training costs, that the Utility was able to avoid due to the pandemic.

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On January 18, 2023, the Utility, The Utility Reform Network (“TURN”), and the Public Advocates Office of the CPUC filed a joint motion for approval of a settlement agreement, pursuant to which the Utility would receive a revenue requirement of $720.7 million. The settlement agreement does not address $591.9 million recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

Upon approval, the majority of the Utility’s proposed revenue requirement would be collected over a two-year period.

2022 WMCE Application

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 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 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. The costs addressed in the 2022 WMCE application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. In connection with the 2022 WMCE application, the Utility also requested interim rate relief of $1.1 billion to be recovered over 12 months beginning June 1, 2023. The remaining $224 million would be recovered after the CPUC issues a final decision. On April 28, 2023, the ALJ issued a proposed decision granting the Utility’s request for interim rate relief.

On April 7, 2023, the assigned commissioner issued a scoping memo pursuant to which a proposed decision would be issued by the first quarter of 2024.

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 “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on approved revenue requirements and 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 forward-looking rate cases that are pending, have pending appeals, or were completed during the three months ended March 31, 2023 are summarized in the following table:

Rate Case	Request	Status
2023 GRC	Revenue requirement of $15.82 billion for 2023	A decision is scheduled for the third quarter of 2023.
2023 Cost of Capital	Increase ROE to 11% and cost of debt to 4.31%	Final decision issued December 2022, adopting a 10% ROE. Intervenor filed application for rehearing in January 2023.

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2023 General Rate Case

On July 22, 2022, the Utility submitted a request for the second track of the GRC proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $206 million in expenses and $129 million in capital expenditures, resulting in a proposed revenue requirement of approximately $241 million, most of which is proposed to be collected over a two-year period beginning August 1, 2023. On January 6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023. The self-insurance will be funded through CPUC-jurisdictional rates at $400 million for test year 2023 and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected in rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. As a result, the Utility could collect the self-insurance amounts over a longer period than it makes wildfire-related payments. The settlement agreement includes a five percent deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market.

The CPUC’s schedule indicated a final decision on both tracks of this proceeding would be issued in the third quarter of 2023.

Cost of Capital Proceedings

2023 Cost of Capital Application

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital including 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 for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision. See the 2022 Form 10-K.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The decision deferred consideration of the proposal to a second phase of the proceeding.

Transmission Owner Rate Cases

The Transmission Owner rate cases for 2017, 2018, and 2019 (the TO18, TO19, and TO20 rate case, respectively) remain outstanding. For more information, see the 2022 Form 10-K.

Other Regulatory Proceedings

2020-2022 Wildfire Mitigation Plans

On February 25, 2022, the Utility submitted the 2022 WMP. The 2022 WMP addressed the Utility’s wildfire safety programs and initiatives 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 November 10, 2022, OEIS approved the Utility’s 2022 WMP. On December 15, 2022, the CPUC ratified OEIS’s approval.

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On February 26, 2023, OEIS issued its final Annual Report on Compliance (“ARC”) for the Utility’s 2020 WMP. In the final ARC, OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets but found that the Utility did not substantially comply with the WMP during the 2020 compliance period. On March 24, 2023, the Utility filed a writ in California superior court seeking judicial review of the OEIS ARC on the grounds that OEIS failed to utilize the compliance evaluation criteria adopted by the CPUC. If the court sustains the ARC’s finding that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance. PG&E Corporation and the Utility cannot reasonably estimate whether they will incur a loss in connection with the ARC or the amount of any such loss, as the writ is pending in state court and because any penalty issued by CPUC depends upon various factors.

2023-2025 Wildfire Mitigation Plan

On March 27, 2023, the Utility submitted the 2023-2025 WMP. The 2023-2025 WMP addresses the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment and reducing the customer impact of EPSS and PSPS events.

Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter.

On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation.

On January 20, 2023, the CPUC issued a scoping memo. On March 30, 2023, the ALJ modified the procedural schedule, pursuant to which a proposed decision would be issued by January 2024.

Self-Reports to the CPUC

The Utility self-reports potential violations of certain requirements to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these potential violations, including under the EOEP. For more information about the EOEP, see “PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process” in Item 1A. Risk Factors in the 2022 Form 10-K. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

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 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. 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.

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, accordingly, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. In addition to its plan to complete the intrusive tests by September 30, 2023, the Utility is performing an end-to-end assessment of the wood pole test and treat program to proactively identify and address potential issues.

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The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

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 ALJ issued a ruling updating case status, which states that the proceeding will remain open as a vehicle to monitor the progress of the Utility in improving its safety culture and to address any relevant issues that arise, with the CPUC’s consultant continuing in a monitoring role. The ruling states that additional issues may be raised in the proceedings by parties or the CPUC.

On April 13, 2023, the ALJ issued a proposed decision that would close this proceeding but allow for the continued monitoring of the Utility’s safety culture through an advice letter process.

Extension of Diablo Canyon Operations

On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility would continue to operate Diablo Canyon on behalf of all CPUC-jurisdictional load serving entities, and all customers of those load serving entities would be responsible for the cost of extended operations.

The key remaining steps to continued operations include NRC license renewal and approvals from California state agencies. If either is not received, the Utility would retire Unit 1 in 2024 and Unit 2 in 2025 as previously approved by the CPUC.

On October 31, 2022, the Utility requested that the NRC resume its review of a license renewal application the Utility voluntarily withdrew and terminated in 2018 or else grant an exemption to permit operations to continue at Diablo Canyon after the expiration of each of its current operating licenses and until the NRC completes its review of the license renewal application. On January 24, 2023, the NRC staff declined to resume its review of the previously-withdrawn application and directed the Utility to submit a new application for license renewal, which the Utility expects to do by the end of 2023. On March 2, 2023, the NRC approved the Utility’s exemption request to allow continued operations at Diablo Canyon past the plant’s current licenses. This exemption will allow the Utility, similar to exemptions granted to other utilities, to continue operating both units at Diablo Canyon while the Utility’s license renewal application is under review.

Consistent with SB 846, the CPUC, the California Energy Resources Conservation and Development Commission, California State Lands Commission, California Coastal Commission, and other state agencies will need to determine that extended operations represent an appropriate path to meet California’s reliability, affordability, and environmental goals.

On February 28, 2023 and in consultation with the CAISO and CPUC, the California Energy Resources Conservation and Development Commission determined that California needs to extend the operation of Diablo Canyon to support electric system reliability and that it is prudent to extend the operation of Diablo Canyon for calendar years 2024 through 2030.

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LEGISLATIVE AND REGULATORY INITIATIVES

Inflation Reduction Act

In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax (“CAMT”) on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for renewable and clean energy sources. Many aspects of the Inflation Reduction Act, including the CAMT, remain uncertain and the U.S. Department of the Treasury and the Internal Revenue Service have been granted broad authority to enact regulations implementing its provisions. Depending on the guidance issued, PG&E Corporation and the Utility’s federal income tax liability could increase substantially. PG&E Corporation and the Utility continue to evaluate the impact of the law and its potential implications.

Revenue Procedure 2023-15

On April 14, 2023, the Internal Revenue Service issued Revenue Procedure 2023-15, which provides a safe harbor method for determining gas repairs deductions for income tax purposes. PG&E Corporation and the Utility are currently evaluating the impact of the law.

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 substances; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this quarterly report on Form 10-Q, as well as “Item 1A. Risk Factors” and Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows.  The Utility uses derivative instruments only for risk mitigation purposes and not for speculative purposes.  The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments.  Some contracts are accounted for as leases.  The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate.  Credit limits and credit quality are monitored periodically.  These activities are discussed in detail in the 2022 Form 10-K.  There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the three months ended March 31, 2023.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, contributions to the Wildfire Fund, and pension and other post-retirement benefit plans to be critical accounting policies. These policies are considered 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 discussed in detail in the 2022 Form 10-K.

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ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	(Unaudited)
	Three Months Ended March 31,
	2023		2022
Operating Revenues
Electric	$	4,119	$	4,158
Natural gas	2,090		1,640
Total operating revenues	6,209		5,798
Operating Expenses
Cost of electricity	522		502
Cost of natural gas	916		561
Operating and maintenance	2,677		3,110
SB 901 securitization charges, net	273		—
Wildfire-related claims, net of recoveries	(2)		(1)
Wildfire Fund expense	117		118
Depreciation, amortization, and decommissioning	1,077		972
Total operating expenses	5,580		5,262
Operating Income	629		536
Interest income	112		8
Interest expense	(602)		(419)
Other income, net	85		149
Income Before Income Taxes	224		274
Income tax benefit	(348)		(204)
Net Income	572		478
Preferred stock dividend requirement of subsidiary	3		3
Income Available for Common Shareholders	$	569	$	475
Weighted Average Common Shares Outstanding, Basic	1,991		1,986
Weighted Average Common Shares Outstanding, Diluted	2,132		2,134
Net Income Per Common Share, Basic	$	0.29	$	0.24
Net Income Per Common Share, Diluted	$	0.27	$	0.22

See accompanying Notes to the Condensed Consolidated Financial Statements.

31

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2023		2022
Net Income	$	572	$	478
Other Comprehensive Income
Net unrealized gains on available-for-sale securities (net of taxes of $2 and $0, respectively)	5		—
Total other comprehensive income	5		—
Comprehensive Income	577		478
Preferred stock dividend requirement of subsidiary	3		3
Comprehensive Income Attributable to Common Shareholders	$	574	$	475

See accompanying Notes to the Condensed Consolidated Financial Statements.

32

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

	(Unaudited)
	Balance at
	March 31, 2023		December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	1,028	$	734
Restricted cash (includes $385 million and $201 million related to VIEs at respective dates)	387		213
Accounts receivable
Customers (net of allowance for doubtful accounts of $241 million and $166 million at respective dates) (includes $2.13 billion and $2.47 billion related to VIEs, net of allowance for doubtful accounts of $241 million and $166 million at respective dates)	2,568		2,645
Accrued unbilled revenue (includes $1.05 billion and $1.16 billion related to VIEs at respective dates)	1,201		1,304
Regulatory balancing accounts	3,392		3,264
Other	1,381		1,624
Regulatory assets	305		296
Inventories
Gas stored underground and fuel oil	34		91
Materials and supplies	801		751
Wildfire Fund asset	460		460
Other	740		1,433
Total current assets	12,297		12,815
Property, Plant, and Equipment
Electric	76,034		74,772
Gas	28,578		28,226
Construction work in progress	4,280		4,137
Financing lease and other	19		19
Total property, plant, and equipment	108,911		107,154
Accumulated depreciation	(31,591)		(30,946)
Net property, plant, and equipment	77,320		76,208
Other Noncurrent Assets
Regulatory assets	16,662		16,443
Customer credit trust	602		745
Nuclear decommissioning trusts	3,438		3,297
Operating lease right of use asset	1,448		1,311
Wildfire Fund asset	4,732		4,847
Income taxes receivable	9		9
Other (includes noncurrent accounts receivable of $8 million and $17 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $1 million at respective dates)	3,104		2,969
Total other noncurrent assets	29,995		29,621
TOTAL ASSETS	$	119,612	$	118,644

See accompanying Notes to the Condensed Consolidated Financial Statements.

33

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

	(Unaudited)
	Balance at
	March 31, 2023		December 31, 2022
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,295	$	2,055
Long-term debt, classified as current (includes $178 million and $168 million related to VIEs at respective dates)	3,726		2,268
Accounts payable
Trade creditors	2,324		2,888
Regulatory balancing accounts	1,452		1,658
Other	751		778
Operating lease liabilities	177		231
Interest payable (includes $213 million and $116 million related to VIEs at respective dates)	566		626
Wildfire-related claims	1,515		1,912
Other	2,995		3,372
Total current liabilities	14,801		15,788
Noncurrent Liabilities
Long-term debt (includes $10.33 billion and $10.31 billion related to VIEs at respective dates)	48,508		47,742
Regulatory liabilities	18,119		17,630
Pension and other postretirement benefits	232		231
Asset retirement obligations	5,916		5,912
Deferred income taxes	2,588		2,732
Operating lease liabilities	1,468		1,243
Other	4,394		4,291
Total noncurrent liabilities	81,225		79,781
Equity
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,995,774,083 and 1,987,784,948 shares outstanding at respective dates	32,214		32,887
Treasury stock, at cost; 187,743,590 and 247,743,590 shares at respective dates	(1,907)		(2,517)
Reinvested earnings	(6,973)		(7,542)
Accumulated other comprehensive loss	—		(5)
Total shareholders’ equity	23,334		22,823
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	23,586		23,075
TOTAL LIABILITIES AND EQUITY	$	119,612	$	118,644

See accompanying Notes to the Condensed Consolidated Financial Statements.

34

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	(Unaudited)
	Three Months Ended March 31,
	2023		2022
Cash Flows from Operating Activities
Net income	$	572	$	478
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,077		972
Bad debt expense	139		43
Allowance for equity funds used during construction	(41)		(42)
Deferred income taxes and tax credits, net	(163)		(16)
Wildfire Fund expense	117		118
Other	(6)		148
Effect of changes in operating assets and liabilities:
Accounts receivable	826		543
Wildfire-related insurance receivable	51		43
Inventories	7		(22)
Accounts payable	303		217
Wildfire-related claims	(396)		(631)
Other current assets and liabilities	(239)		(113)
Regulatory assets, liabilities, and balancing accounts, net	(1,069)		63
Other noncurrent assets and liabilities	7		(140)
Net cash provided by operating activities	1,185		1,661
Cash Flows from Investing Activities
Capital expenditures	(2,288)		(2,310)
Proceeds from sales and maturities of nuclear decommissioning trust investments	277		421
Purchases of nuclear decommissioning trust investments	(303)		(447)
Proceeds from sales and maturities of customer credit trust investments