UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549
					FORM	10-Q
(Mark One)
☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the quarterly period ended				September 30, 2022
			OR
☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission File Number				Exact Name of Registrant as Specified in its Charter			State or Other Jurisdiction of Incorporation				IRS Employer Identification Number
1-12609				PG&E Corporation			California				94-3234914
1-2348				Pacific Gas and Electric Company			California				94-0742640
PG&E Corporation							Pacific Gas and Electric Company
77 Beale Street							77 Beale Street
P.O. Box 770000							P.O. Box 770000
San Francisco,		California	94177				San Francisco,		California	94177
Address of principal executive offices, including zip code
PG&E Corporation							Pacific Gas and Electric Company
415	973-1000						415	973-7000
Registrant’s telephone number, including area code

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

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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 October 20, 2022:
PG&E Corporation:	2,465,443,675*
Pacific Gas and Electric Company:	264,374,809
*Includes 342,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 135,000,000 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 SEPTEMBER 30, 2022

TABLE OF CONTENTS

		SEC Form 10-Q Reference Number
GLOSSARY
FORWARD-LOOKING STATEMENTS
	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	Part I, Item 2
	OVERVIEW
	RESULTS OF OPERATIONS
	LIQUIDITY AND FINANCIAL RESOURCES
	ENFORCEMENT AND LITIGATION MATTERS
	REGULATORY MATTERS
	LEGISLATIVE AND REGULATORY INITIATIVES
	ENVIRONMENTAL MATTERS
	RISK MANAGEMENT ACTIVITIES
	CRITICAL ACCOUNTING ESTIMATES
	ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
	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: BANKRUPTCY FILING
	NOTE 3: SIGNIFICANT ACCOUNTING POLICIES
	NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
	NOTE 5: DEBT
	NOTE 6: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
	NOTE 7: EQUITY
	NOTE 8: EARNINGS PER SHARE
	NOTE 9: DERIVATIVES
	NOTE 10: FAIR VALUE MEASUREMENTS
	NOTE 11: WILDFIRE-RELATED CONTINGENCIES
	NOTE 12: 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
	RISK FACTORS	Part II, Item 1A

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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	Part II, Item 2
EXHIBITS	Part II, Item 6
SIGNATURES

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GLOSSARY

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

2021 Form 10-K	PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2021
Form 10-Q	PG&E Corporation’s and Utility’s joint Quarterly Report on Form 10-Q for the period ended September 30, 2022
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
APD	alternate proposed decision
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB
Bankruptcy Code	the United States Bankruptcy Code
Bankruptcy Court	the U.S. Bankruptcy Court for the Northern District of California
CAISO	California Independent System Operator Corporation
Cal Fire	California Department of Forestry and Fire Protection
CAPP	California Arrearage Payment Program
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
Corporation Revolving Credit Agreement	Credit Agreement, dated as of July 1, 2020, as amended, by and among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent
CHT	Customer Harm Threshold
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	Department of Energy
DTSC	Department of Toxic Substances Control
DWR	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
EPSS	Enhanced Powerline Safety Settings
EVM	enhanced vegetation management
Exchange Act	Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
FHPMA	Fire Hazard Prevention Memorandum Account
Fire Victim Trust	The trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be funded
FRMMA	Fire Risk Mitigation Memorandum Account
GAAP	U.S. Generally Accepted Accounting Principles

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GRC	general rate case
GT&S	gas transmission and storage
HSMA	hazardous substance memorandum account
IRC	Internal Revenue Code
IOUs	investor-owned utility(ies)
Kincade Amended Complaint	The amended criminal complaint filed by the Sonoma County District Attorney’s Office on January 28, 2022 in connection with the 2019 Kincade fire
Kincade Complaint	The criminal complaint filed by the Sonoma County District Attorney’s Office on April 6, 2021 in connection with the 2019 Kincade fire
Lakeside Building	300 Lakeside Drive, Oakland, California, 94612
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
MGMA	Microgrids Memorandum Account
MGP	manufactured gas plants
MW	megawatt
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceeding
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
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
OIR	order instituting rulemaking
Pacific Generation	Pacific Generation, LLC
PD	proposed decision
PERA	Public Employees Retirement Association
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
RA	Resource Adequacy
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
ROU asset	right-of-use asset
RTBA	Risk Transfer Balancing Account
RUBA	Residential Uncollectibles Balancing Account
SB	Senate Bill
SEC	U.S. Securities and Exchange Commission
Securities Act	The Securities Act of 1933
SED	Safety and Enforcement Division of the CPUC
SFGO	The Utility’s 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
SOFR	Secured Overnight Financing Rate

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SPV	PG&E AR Facility, LLC
Tax Act	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
VSP	voluntary separation program
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
WMCE	Wildfire Mitigation and Catastrophic Events
WMP	wildfire mitigation plan
WMPMA	Wildfire Mitigation Plan Memorandum Account
Zogg Complaint	The criminal complaint filed by the Shasta County District Attorney’s Office on September 24, 2021

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines associated with various investigations and proceedings; forecasts of capital expenditures; forecasts of expense reduction; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “commit,” “goal,” “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 recoverability 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 territory, including the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), the wildfire that began on September 27, 2020 in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), the wildfire that began on July 13, 2021 near the Cresta Dam in the Feather River Canyon in Plumas County, California (the “2021 Dixie fire”), 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 and three other fires in Shasta County, California; potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other enforcement agency were to bring an enforcement action in respect of any such fire; the risk that the Utility is not able to recover costs from insurance, from the Wildfire Fund or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations and proceedings;

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

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

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

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

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

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

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

•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 the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

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

◦privacy and cybersecurity; and

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◦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; and including 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;

•whether the Utility can control its operating costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing a streamlined organizational structure and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

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

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

•the risks and uncertainties associated with the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing litigation, including appeals of the Confirmation Order; certain indemnity obligations to current and former officers and directors, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings; three purported class actions that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509; the debarment proceeding; the purported PSPS class action filed in December 2019; and other third-party claims, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•the ability of PG&E Corporation and the Utility to securitize the remaining $2.4 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;

•PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases and the financial and other restructuring undergone by PG&E Corporation and the Utility in connection with their emergence from Chapter 11;

•the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;

•the impact that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to community choice aggregators, direct access providers and legislative mandates to replace gas-fuel technologies, have on the Utility’s ability to make and recover its investments through rates and earn its authorized ROE, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, and changing customer demand for its natural gas and electric services;

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•the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

•the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

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

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

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

•the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as on energy demand in the Utility’s service territory, the ability of the Utility to collect on customer receivables, the ability of the Utility to mitigate these effects, including with spending reductions, the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions caused either by illness of workers and their family members or workforce attrition related to potential new workplace regulations such as vaccine mandates;

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

•the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors in this Form 10-Q and the 2021 Form 10-K and a detailed discussion of these matters contained in Item 2. MD&A in the 2021 Form 10-K and 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.

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 “Chapter 11,” “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. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

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PART I. 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 2021 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 Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives and third-party suppression efforts are expected to influence the frequency and severity of future wildfires. To the extent that future wildfires occur in the Utility’s service territory, the Utility may incur costs associated with the investigations of the causes and origins of such fires, even if it is subsequently determined that such fires were not caused by the Utility’s facilities. The financial impact of future wildfires could be mitigated through insurance, the Wildfire Fund, or other forms of cost recovery. However, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events, including coverage limitations applicable to different insurance layers. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any Wildfire Fund coverage year (“Coverage Year”) that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires and serves as an alternative to traditional insurance products, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. See “Loss Recoveries” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, even if the Utility satisfies the ongoing eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising from wildfires that occurred between July 12, 2019 and the Utility’s emergence from Chapter 11 on July 1, 2020, the availability of the Wildfire Fund to pay such claims would be capped at 40% of the allowed amount of such claims. See “Wildfire Fund under AB 1054” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

•The Costs, Effectiveness, and Execution of the Utility’s Wildfire Mitigation Initiatives. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur, and the impact of PSPS events.

PG&E Corporation and the Utility have incurred substantial expenditures in connection with the 2020-2022 WMP. For more information, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The Utility expects that its wildfire mitigation initiatives will continue to involve substantial and ongoing expenditures. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain.

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The Utility has implemented operational changes and investments that reduce wildfire risk, including the EPSS, PSPS, vegetation management, asset inspection, and system hardening programs. These programs, particularly the PSPS and EPSS programs, have been the subject of scrutiny and criticism by various stakeholders, including the California governor, the CPUC, and the court that oversaw the Utility’s probation. The PSPS and EPSS programs have had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators, and policymakers, and future PSPS and EPSS events may increase these negative perceptions.

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

While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. The success of the Utility’s wildfire mitigation efforts depends on many factors, including on whether the Utility is able to retain or contract for the workforce necessary to execute its wildfire mitigation actions.

•The Timing and Outcome of Ratemaking and Other Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its FERC TO18 rate case and the resulting impact on the TO19 and TO20 rate cases, 2023 GRC, 2020 and 2021 WMCE, and cost of capital applications and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, WMPMA, FRMMA, CPPMA, VMBA, WMBA, and RTBA. The Utility’s financial results may be impacted by the timing and outcome of its application to transfer its non-nuclear generation assets to Pacific Generation and the potential sale of 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 4 and 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.

•The Impact of Wildfires. PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire are significant and may be excluded from any potential amounts recoverable under applicable insurance policies, the WEMA, FERC TO rates, or the Wildfire Fund under AB 1054. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. Liabilities in excess of recoverable amounts for these wildfires could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

As of September 30, 2022, PG&E Corporation and the Utility had recorded an aggregate liability of $950 million, $375 million, $1.15 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. Claims related to the 2019 Kincade fire that were not satisfied in full as of the Emergence Date were not discharged in connection with emerging from Chapter 11.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors in connection with the 2020 Zogg fire and three other fires in Shasta County, California. If the Utility were to be convicted of certain charges in the Zogg Complaint, the Utility could be subject to material fines, penalties, and restitution, as well as non-monetary remedies such as oversight requirements, and accordingly the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2020 Zogg fire would materially exceed the $375 million of aggregate liability that PG&E Corporation and the Utility have recorded.

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If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Coverage Year, the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount, except that recoveries for the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy, and recoveries for each of these fires would also be subject to the other limitations and requirements under AB 1054. As of September 30, 2022, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $347 million for the 2020 Zogg fire, $553 million for the 2021 Dixie fire, and $40 million for the 2022 Mosquito fire. As of September 30, 2022, the Utility has recorded regulatory recovery and Wildfire Fund receivables of $473 million and $150 million, respectively, for the 2021 Dixie fire. As of September 30, 2022, the Utility has recorded regulatory recovery of $60 million for the 2022 Mosquito fire. The Utility’s recorded receivables for regulatory recovery and with respect to the Wildfire Fund take into account the revised prudency standard and the presumption of reasonableness of the Utility’s conduct under AB 1054. 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 receivable. There can be no assurance that such amounts will ultimately be recovered, and the Utility does not expect that any of its liability insurance would cover restitution payments, if such payments were ordered by the court presiding over the criminal proceeding in connection with the 2020 Zogg fire. See “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information.

•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the Safety Culture OII, and potential penalties in connection with the Utility’s WMP and safety and other self-reports. See Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K. In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. See “Jurisdictions may attempt to acquire the Utility’s assets through eminent domain.” in Item 1A. Risk Factors for more information. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California.

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

•The Impact of the COVID-19 Pandemic. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic. 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 and the cap on the number of service disconnections for residential customers. The Utility continues to monitor the overall impact of the COVID-19 pandemic. PG&E Corporation and the Utility expect additional financial impacts in the future as a result of the COVID-19 pandemic. Other impacts of the COVID-19 pandemic on PG&E Corporation and the Utility have included operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility’s operations, higher credit spreads and borrowing costs and could potentially also include a reduction in revenue due to the cost of capital adjustment mechanism and incremental financing needs. For more information on the impact of the COVID-19 pandemic on PG&E Corporation and the Utility, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic.” in Item 1A. Risk Factors in the 2021 Form 10-K and “COVID-19” in Liquidity and Financial Resources below.

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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 this Form 10-Q and the 2021 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 $21.1 billion and California net operating loss carryforward of approximately $18.9 billion as of December 31, 2021.

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 January 31, 2022, April 14, 2022, and October 4, 2022, the Fire Victim Trust exchanged 40,000,000, 60,000,000, and 35,000,000 Plan Shares, respectively, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. In the nine months ended September 30, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 100,000,000 shares resulted in an aggregate tax benefit of $337 million 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 2,465,443,675 shares outstanding as of October 20, 2022, only 1,644,956,495 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 October 20, 2022, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of October 20, 2022 was 3.16% of outstanding shares. As of October 20, 2022, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 135,000,000 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 and nine months ended September 30, 2022 and 2021. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) attributable to common shareholders for the three and nine months ended September 30, 2022 and 2021:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Consolidated Total	$	456	$	(1,091)	$	1,287	$	(574)
PG&E Corporation	(31)		(46)		(323)		(139)
Utility	$	487	$	(1,045)	$	1,610	$	(435)

PG&E Corporation’s net loss primarily consists of income taxes, interest expense on long-term debt, and charges related to Wildfire-Related Securities Claims. For more information on Wildfire-Related Securities Claims, see Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2022 and 2021.  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 September 30, 2022						Three Months Ended September 30, 2021
	Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	2,603	$	1,292	$	3,895	$	2,659	$	1,522	$	4,181
Natural gas operating revenues	1,137		362		1,499		998		286		1,284
Total operating revenues	3,740		1,654		5,394		3,657		1,808		5,465
Cost of electricity	—		1,032		1,032		—		1,133		1,133
Cost of natural gas	—		257		257		—		176		176
Operating and maintenance	1,771		477		2,248		2,250		543		2,793
Wildfire-related claims, net of recoveries	9		—		9		94		—		94
Wildfire Fund expense	118		—		118		162		—		162
Depreciation, amortization, and decommissioning	1,002		—		1,002		801		—		801
Total operating expenses	2,900		1,766		4,666		3,307		1,852		5,159
Operating income (loss)	840		(112)		728		350		(44)		306
Interest income	42		—		42		—		—		—
Interest expense	(458)		—		(458)		(342)		—		(342)
Other income, net	15		112		127		89		44		133
Income before income taxes	439		—		439		97		—		97
Income tax provision (benefit) (1)					(51)						1,139
Net income (loss)					490						(1,042)
Preferred stock dividend requirement (1)					3						3
Income (Loss) Available for Common Shareholders					$	487					$	(1,045)

(1) These items impacted earnings for the three months ended September 30, 2022 and 2021.

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	Nine Months Ended September 30, 2022						Nine Months Ended September 30, 2021
	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	$	7,893	$	3,850	$	11,743	$	7,544	$	3,983	$	11,527
Natural gas operating revenues	2,992		1,575		4,567		2,821		1,048		3,869
Total operating revenues	10,885		5,425		16,310		10,365		5,031		15,396
Cost of electricity	—		2,314		2,314		—		2,570		2,570
Cost of natural gas	—		1,177		1,177		—		670		670
Operating and maintenance	5,293		2,272		7,565		5,782		1,923		7,705
SB 901 securitization charges, net	40		—		40		—		—		—
Wildfire-related claims, net of recoveries	153		—		153		261		—		261
Wildfire Fund expense	353		—		353		399		—		399
Depreciation, amortization, and decommissioning	2,915		—		2,915		2,540		—		2,540
Total operating expenses	8,754		5,763		14,517		8,982		5,163		14,145
Operating income (loss)	2,131		(338)		1,793		1,383		(132)		1,251
Interest income	71		—		71		17		—		17
Interest expense	(1,175)		—		(1,175)		(1,032)		—		(1,032)
Other income, net	77		338		415		258		132		390
Reorganization items, net	—		—		—		(12)		—		(12)
Income before income taxes	1,104		—		1,104		614		—		614
Income tax provision (benefit) (1)					(516)						1,039
Net income (loss)					1,620						(425)
Preferred stock dividend requirement (1)					10						10
Income (Loss) Available for Common Shareholders					$	1,610					$	(435)

(1) These items impacted earnings for the nine months ended September 30, 2022 and 2021.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three and nine months ended September 30, 2022 and 2021, 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 $83 million, or 2%, in the three months ended September 30, 2022, compared to the same period in 2021, primarily due to the recognition of approximately $180 million in revenues related to the final decision approving $356.3 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its GT&S system (see “2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below), increased base revenues authorized in the 2020 GRC, and additional revenues as authorized through the FERC formula rate. The increases were partially offset by approximately $80 million of previously deferred revenues recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below).

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The Utility’s electric and natural gas operating revenues that impacted earnings increased by $520 million, or 5%, in the nine months ended September 30, 2022, compared to the same period in 2021, primarily due to the recognition of approximately $310 million in revenues related to the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below), the recognition of approximately $180 million in revenues related to the final decision approving $356.3 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its GT&S system (see “2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below), increased base revenues authorized in the 2020 GRC, and additional revenues as authorized through the FERC formula rate. These increases were partially offset by a decrease of approximately $80 million of previously deferred revenues recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below).

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings decreased by $479 million, or 21%, in the three months ended September 30, 2022, compared to the same period in 2021, as a result of operating cost efficiencies and decreases in the recognition of previously deferred costs including approximately $80 million recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below) in the three months ended September 30, 2021 with no comparable charge in the same period in 2022. In addition, in the three months ended September 30, 2021, the Utility recorded a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable charge in the same period in 2022.

The Utility’s operating and maintenance expenses that impacted earnings decreased by $489 million, or 8%, in the nine months ended September 30, 2022, compared to the same period in 2021, as a result of operating cost efficiencies and decreases in the recognition of previously deferred costs including $90 million related to residential uncollectibles and $105 million recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below). In addition, during the nine months ended September 30, 2021, the Utility recorded a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable charge in the same period in 2022. These decreases were partially offset by 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” below) in the nine months ended September 30, 2022, compared to the same period in 2021.

SB 901 Securitization Charges, Net

SB 901 securitization charges, net, that impacted earnings increased by $40 million, or 100%, in the nine months ended September 30, compared to the same period in 2021. In the second quarter of 2022, as a result of the establishment of the SB 901 securitization regulatory asset and liability, the Utility recorded a $40 million charge. For more information, see Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Wildfire-Related Claims, Net of Recoveries

Costs related to wildfires that impacted earnings decreased by $85 million, or 90% in the three months ended September 30, 2022, compared to the same period in 2021. The Utility recognized pre-tax charges of $100 million related to the 2022 Mosquito fire in the three months ended September 30, 2022, as compared to pre-tax charges of $1.15 billion related to the 2021 Dixie fire in the three months ended September 30, 2021. The 2022 Mosquito fire charges were partially offset by $90 million of probable recoveries through insurance and the WEMA in the three months ended September 30, 2022, as compared to $1.06 billion of probable recoveries through insurance, the WEMA, and the Wildfire Fund related to the 2021 Dixie fire in the three months ended September 30, 2021. See “Loss Recoveries” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below.

Costs related to wildfires that impacted earnings decreased by $108 million, or 41%, in the nine months ended September 30, 2022, compared to the same period in 2021. The Utility recognized pre-tax charges of $150 million related to the 2019 Kincade fire and $100 million related to the 2022 Mosquito fire in the nine months ended September 30, 2022, as compared to pre-tax charges of $1.15 billion related to the 2021 Dixie fire, $175 million related to the 2019 Kincade fire, and $100 million related to the 2020 Zogg fire in the nine months ended September 30, 2021. The 2022 Mosquito fire charges were partially offset by $90 million of probable recoveries through insurance and the WEMA in the nine months ended September 30, 2022, as compared to $1.06 billion of probable recoveries through insurance, the WEMA, and the Wildfire Fund related to the 2021 Dixie fire and $108 million of probable insurance recoveries related to the 2020 Zogg fire in the nine months ended September 30, 2021. See “Loss Recoveries” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below.

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Wildfire Fund Expense

The Utility’s Wildfire Fund expense that impacted earnings decreased by $44 million, or 27%, and $46 million, or 12%, in the three and nine months ended September 30, 2022, respectively, compared to the same periods in 2021, primarily due to accelerated amortization of the Wildfire Fund asset recorded in 2021 as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire, with no comparable amounts recorded in 2022.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by $201 million, or 25%, and $375 million, or 15%, in the three and nine months ended September 30, 2022, respectively, compared to the same periods in 2021, primarily due to capital additions and an increase in decommissioning expense beginning in January 2022 as a result of the final 2018 NDCTP decision.

Interest Income

Interest income that impacted earnings increased by $42 million, or 100%, and increased by $54 million, or 318%, in the three and nine months ended September 30, 2022, respectively, compared to the same periods in 2021, primarily due to higher interest rates earned on regulatory balancing accounts.

Interest Expense

Interest expense that impacted earnings increased by $116 million, or 34%, and increased by $143 million, or 14%, in the three and nine months ended September 30, 2022, respectively, compared to the same periods in 2021, 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.

Reorganization Items, Net

There was no material change to reorganization items, net that impacted earnings for the periods presented.

Income Tax Provision (Benefit)

Income tax benefit increased by $1,190 million and $1,555 million, in the three and nine months ended September 30, 2022, respectively, compared to the same periods in 2021, primarily due to a write-off of a deferred tax asset associated with the grantor trust election for the Fire Victim Trust in the three and nine months ended September 30, 2021 with no comparable amount in 2022. Additionally, income tax provision increased due to a benefit recognized related to the sale of shares in the Fire Victim Trust in the nine months ended September 30, 2022 with no comparable benefits in the same period in 2021. The income tax provision also increased due to a higher pre-tax income in the three and nine months ended September 30, 2022, compared to the same periods in 2021.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(4.8)	%	303.4	%	(10.9)	%	45.3	%
Effect of regulatory treatment of fixed asset differences (2)	(34.6)	%	(156.8)	%	(32.4)	%	(57.4)	%
Tax credits	(0.8)	%	(3.3)	%	(0.9)	%	(1.5)	%
Fire Victim Trust (3)	—	%	994.5	%	(22.9)	%	155.4	%
Other, net	7.6	%	29.6	%	(0.7)	%	6.6	%
Effective tax rate	(11.6)	%	1,188.4	%	(46.8)	%	169.4	%

(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 Tax Act.

(3) Includes the effect of the grantor trust election for the Fire Victim Trust in the three and nine months ended September 30, 2021. Includes the effect of the grantor trust election for the Fire Victim Trust and the tax benefit for the sale of shares by the Fire Victim Trust in the nine months ended September 30, 2022. See “Tax Matters” above and Note 7 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.  Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost effectiveness of each source of electricity.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Cost of purchased power, net	$	879	$	1,017	$	2,016	$	2,344
Fuel used in generation facilities	153		116		298		226
Total cost of electricity	$	1,032	$	1,133	$	2,314	$	2,570

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2022		2021		2022		2021
Cost of natural gas sold	$	224	$	144	$	1,070	$	567
Transportation cost of natural gas sold	33		32		107		103
Total cost of natural gas	$	257	$	176	$	1,177	$	670

Operating and Maintenance Expenses

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

Other Income, Net

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

Nuclear Operations

Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of Diablo Canyon’s generation to the California electricity market. Management analyzes capacity factors by comparing Diablo Canyon’s actual generation to forecasted annual capacity factors, which reflect planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms. Capacity factors do not currently impact PG&E Corporation’s and the Utility’s results of operations, except to the extent requested cost recovery is denied because the costs are found to be imprudently incurred.

Apart from cost-of-service ratemaking and beginning on September 2, 2022, the Utility is entitled to receive a monthly performance-based disbursement. (See “Senate Bill 846” below.)

The Utility manages its scheduled refueling outages with the objective of minimizing their duration and maintaining high nuclear generating capacity factors, resulting in a stable generation base for the Utility’s wholesale and retail power marketing activities. During scheduled refueling outages, the Utility performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the year ended December 31, 2021, and the nine months ended September 30, 2022, Diablo Canyon achieved an average capacity factor of 84% and 94%, respectively. As previously disclosed, Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to malfunctions within the main generator associated with excessive vibration.

In addition to the maintenance and equipment upgrades performed by the Utility during scheduled refueling outages, the Utility has extensive operating and security procedures in place to ensure the safe operation of Diablo Canyon. The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.

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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.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

COVID-19

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic. The outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus (including Delta and Omicron), and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have impacted and will continue to impact the Utility for an indeterminate period of time. 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, the cap 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 has resumed non-residential service and residential service disconnections as of October 13, 2022. The CPUC has set an annual cap on the number of residential disconnections. The Utility’s accounts receivable balances over 30 days outstanding as of September 30, 2022, were approximately $1.1 billion, or $869 million higher as compared to the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic.

As of September 30, 2022, PG&E Corporation and the Utility had access to approximately $2.6 billion of total liquidity comprised of approximately $107 million of Utility cash, $155 million of PG&E Corporation cash and $2.3 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. See “Cost of Capital Proceedings” below for more information.

The Utility established the CPPMA memorandum accounts for tracking costs related to the CPUC’s emergency authorization and order for the period the CPPMA was in effect. As of September 30, 2022, the CPPMA totaled $32 million and is reflected in Long-term regulatory assets on the Condensed Consolidated Balance Sheets. In addition to the $32 million recorded to the CPPMA, the Utility recorded approximately $109 million of undercollections from residential customers from March 4, 2020 to September 30, 2022 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Condensed Consolidated Balance Sheets.

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On June 30, 2022, the Governor of California signed AB 205, which included authorization for additional incremental CAPP funding of $958 million for California IOUs to be determined by the California Department of Community Services and Development. The Utility and the community choice aggregators in its territory expect to receive $219 million to reduce the amounts owed by customer accounts in arrears.

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

Cash and Cash Equivalents

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

Financial Resources

Equity Financings

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in “At the Market Equity Distribution Program” in Note 7 of the Notes to the Condensed Consolidated Financial Statements in Item 1.), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in “At the Market Equity Distribution Program” in Note 7 of the Notes to the Condensed Consolidated Financial Statements in Item 1) with the Forward Purchasers.

As of September 30, 2022, there was $400 million available under PG&E Corporation’s At the Market Equity Distribution Program for future offerings. During the nine months ended September 30, 2022, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement.

PG&E Corporation plans to meet its capital requirements for 2022 and 2023 through internally-generated funds and the issuance of long-term debt, short-term debt, and the potential sale of a minority interest in Pacific Generation. (See “Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets.”) PG&E Corporation does not plan to issue any equity securities in 2022, 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 February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in an amount equal to $1.0 billion, and for general corporate purposes.

On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

As previously disclosed, on August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

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SB 901 Securitization

On May 10, 2022, PG&E Wildfire Recovery Funding LLC, a bankruptcy remote, limited liability company wholly owned by the Utility, issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Due Date
A-1	$	540,000,000	3.594	%	June 1, 2032
A-2	$	540,000,000	4.263	%	June 1, 2038
A-3	$	360,000,000	4.377	%	June 3, 2041
A-4	$	1,260,000,000	4.451	%	December 1, 2049
A-5	$	900,000,000	4.674	%	December 1, 2053

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche	Amount		Interest Rate		Due Date
B-1	$	613,080,000	4.022	%	June 1, 2033
B-2	$	600,000,000	4.722	%	June 1, 2039
B-3	$	500,040,000	5.081	%	June 3, 2043
B-4	$	1,149,960,000	5.212	%	December 1, 2049
B-5	$	1,036,920,000	5.099	%	June 1, 2054

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement as defined below, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024.

Credit Facilities

As of September 30, 2022, PG&E Corporation and the Utility had $500 million and $1.8 billion available under their respective $500 million and $4.0 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 amendment. 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 from time to time.

PG&E Corporation

As previously disclosed, on July 1, 2020, PG&E Corporation entered into the Corporation Revolving Credit Agreement, which it subsequently amended.

On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation).

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Utility

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). The 364-Day 2022A Tranche Loans have a maturity date of April 3, 2023 and bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022A Tranche Loans on April 4, 2022. On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV requested such an increase to the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, extend the scheduled termination date to September 30, 2024 and implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

As previously disclosed, on July 1, 2020, the Utility entered into the Utility Revolving Credit Agreement, which it subsequently amended.

On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

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

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million, which was paid on May 15, 2022, to holders of record on April 29, 2022. On September 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on November 15, 2022, to holders of record on October 31, 2022.

On June 15, 2022, the Board of Directors of the Utility also reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

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Subject to the dividend restrictions as described in Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 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, and other factors that the Board of Directors 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. PG&E Corporation currently is unable to predict when it will commence the payment of dividends on its common stock.

Utility Cash Flows

The Utility’s cash flows were as follows:

	Nine Months Ended September 30,
(in millions)	2022		2021
Net cash provided by operating activities	$	2,940	$	2,220
Net cash used in investing activities	(8,173)		(4,823)
Net cash provided by financing activities	5,304		2,479
Net change in cash, cash equivalents, and restricted cash	$	71	$	(124)

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.  During the nine months ended September 30, 2022, net cash provided by operating activities increased by $720 million compared to the same period in 2021.  This increase was primarily due to a reduction in accounts receivable in 2022 resulting from the CAPP relief payment of approximately $300 million received in January 2022 to reduce the amounts owed by customer accounts in arrears. In addition, during the nine months ended September 30, 2022, the Utility made a payment to the Fire Victim Trust of $592 million as compared to a payment of $758 million in the same period in 2021.

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, Wildfire Fund, and regulatory recoveries;

•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Wildfire-Related Securities Class Action” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Enforcement and Litigation Matters” and “Regulatory Matters” below for more information);

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

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

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

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

•the timing and amount of the gain from the potential sale of a minority interest in Pacific Generation (see “Regulatory Matters” below for more information);

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

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

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.

Investing Activities

Net cash used in investing activities increased by $3.4 billion during the nine months ended September 30, 2022 as compared to the same period in 2021. This increase was primarily driven by a $1.9 billion increase in capital expenditures, including additional system hardening and emergency response work performed in 2022. Additionally, the Utility purchased $1.0 billion of investments as part of the creation of the customer credit trust, with no similar purchases in 2021.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.  The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $7.8 billion and $9.4 billion of capital expenditures in 2022 and between $7.9 billion and $11.2 billion in 2023. Cash provided by or used in investing activities is also driven by proceeds and purchases of customer credit trust investments. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building.

Financing Activities

Net cash provided by financing activities increased by $2.8 billion during the nine months ended September 30, 2022 as compared to the same period in 2021. The increase was due to the issuance of $7.5 billion in SB 901 recovery bonds and a $1.0 billion increase in net borrowings under credit facilities, partially offset by a $4.9 billion decrease in proceeds from issuance of long-term debt, net of repayments, during the nine months ended September 30, 2022, as compared to the same period in 2021. Additionally, the Utility received equity contributions from PG&E Corporation of $427 million, which were offset by common stock dividend payments of $850 million. The net increase was also offset by $370 million of proceeds received in 2021 from the sale of future revenue from transmission tower license sales, with no similar receipts in 2022.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments.  Additionally, future cash flows from financing activities will be affected by the timing and outcome of the Utility’s second AB 1054 securitization transaction, dividend payments, and equity contributions from PG&E Corporation.

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 2, Note 11, and 12 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.

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Enhanced Oversight and Enforcement Process

In the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility’s operational performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics. The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The EOEP does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and OIIs and to impose fines and penalties. The EOEP requires the Utility to report the occurrence of a triggering event to the CPUC’s executive director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

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

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

Vegetation Management

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

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

On October 14, 2022, the CPUC issued a draft resolution authorizing the Utility to exit the EOEP. The CPUC is scheduled to vote on the draft resolution on November 17, 2022.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

During the three months ended September 30, 2022 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters.

•On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon until 2030. The Utility filed an application for federal funding through the U.S. DOE’s Civil Nuclear Credit program on September 2, 2022. On October 18, 2022, the Utility executed the loan agreement with the DWR. On September 29, 2022, the Governor of California also signed SB 884, which authorizes and expedites OEIS and CPUC review of a 10-year undergrounding plan.

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•On September 6, 2022, the Utility submitted update testimony in the 2023 GRC. The update testimony reflects updates for escalation rates and federal tax law and increases the Utility’s revenue requirement request by $835 million for 2023. On October 7, 2022, the Utility filed a settlement agreement with two parties to the proceeding pursuant to which the Utility’s wildfire insurance would be entirely based on self-insurance.

•On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of its non-nuclear generation assets into a stand-alone Utility subsidiary and the potential sale of a minority interest in the newly-formed subsidiary to one or more investors to be identified.

•On September 30, 2022, the CPUC issued a PD and an APD in the Utility’s 2022 cost of capital proceeding. Both the PD and the APD find that an extraordinary event occurred, though only the PD opens a second phase to determine a new 2022 cost of capital.

•On October 6, 2022, OEIS issued a draft decision approving the Utility’s 2022 WMP.

•On October 11, 2022, the CPUC issued a PD and an APD regarding the Utility’s 2020 WMCE application. The Utility intends to seek further review of both proposed decisions.

•On October 14, 2022, the CPUC issued a draft resolution authorizing the Utility to exit the EOEP. The CPUC is scheduled to vote on the draft resolution on November 17, 2022.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC rate requests or that have been deliberately excluded 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 various 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 September 30, 2022, the Utility had recorded an aggregate amount of approximately $5.7 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Of these costs, approximately $800 million was authorized for recovery and accounted for as current, and $4.9 billion was accounted for as long term as of September 30, 2022. See Note 4 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 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1., “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications,” and “Catastrophic Event Memorandum Account Application” 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 nine months ended September 30, 2022 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 filed September 2021. PD and APD issued in October 2022.
2021 WMCE	Revenue requirement of approximately $1.47 billion	PD scheduled for the fourth quarter of 2022.
2018 CEMA	Revenue requirement of $763 million	Settlement agreement to recover $683 million plus interest approved March 2022.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2020 WMCE Application

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

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, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On October 11, 2022, the assigned ALJ issued a PD, and the assigned Commissioner issued an APD. The PD would reject the settlement agreement and result in recovery of a revenue requirement of approximately $748 million. The APD would approve the settlement and authorize recovery of a revenue requirement of $1.04 billion, but would modify the settlement agreement to make permanent a 19% reduction in capital expenditures for future cost-recovery periods through the full service life of the subject assets; the settlement agreement had limited this period to three years. The Utility intends to seek further review of both proposed decisions.

For more information regarding this proceeding, see Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2021 WMCE Application

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

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

The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other 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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The CPUC’s schedule indicates a PD will be issued in the fourth quarter of 2022.

Catastrophic Event Memorandum Account Application

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. The Utility has historically sought such costs through standalone CEMA applications. More recently, the Utility has sought to recover CEMA-eligible costs through its WMCE applications.

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

2018 CEMA Application

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

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

On March 17, 2022, the CPUC approved a settlement agreement authorizing the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount had already been collected in interim rates. The interim rates became final and are no longer subject to refund. The remainder of the authorized revenue requirement will be amortized over a 12-month period, which began on June 1, 2022.

Forward-Looking Rate Cases

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

Decisions in GRC proceedings 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.

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The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the nine months ended September 30, 2022 are summarized in the following table:

Rate Case	Request	Status
2023 GRC	Revenue requirement of $16.18 billion for 2023	Filed amended application March 2022. Submitted updated testimony September 2022. A decision is scheduled in the third quarter of 2023.
2022 Cost of Capital	Leave cost of capital components at pre-2022 levels for 2022	Filed August 2021. PD and APD issued in September 2022.
2023 Cost of Capital	Increase ROE to 11% and cost of debt to 4.31%	Filed April 2022 and updated September 2022. PD expected in November 2022.
2015 GT&S	Revenue requirement of $416 million related to 2011-2014 capital expenditures subject to audit	Final decision issued in July 2022 approving settlement to recover $356 million of revenue requirements.

2023 General Rate Case

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC (“the Original Application”). The 2023 GRC combined what had historically been separated into the GRC and GT&S rate cases. In a GRC, the CPUC approves annual revenue requirements for the first year (a “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the Original Application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service.

Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony. On February 25, 2022 and February 28, 2022, the Utility served supplemental testimony for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility’s service area, the EPSS program, and its EVM program. On March 10, 2022, the Utility filed an amended application that revised and superseded the revenue requirement request in the Original Application. On September 6, 2022, the Utility submitted testimony updating the revenue requirement request in its 2023 GRC proceeding. The testimony reflected updates for escalation rates and federal tax law and guidance since the filing of the Original Application.

As amended and updated, the Utility’s application requests revenue requirements of $16.18 billion and a weighted-average GRC rate base of $50.88 billion for its 2023 test year. The tables below compare the requested revenue requirements and rate base for the GRC period from 2023 through 2026 to those adopted for 2022 in the 2020 GRC and 2019 GT&S proceedings:

(in billions)	2022 (as adopted)		2023		2024		2025		2026
Requested revenue requirement	$	12.21	$	16.18	$	17.22	$	18.08	$	18.76
Requested weighted-average GRC rate base	39.21		50.88		56.81		62.51		68.16

Over the GRC period of 2023 through 2026, the Utility plans to make average annual capital investments of approximately $10.95 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

On July 22, 2022, the Utility submitted a request for the second track of this proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system. 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.

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On October 7, 2022, the Utility filed a settlement agreement with two parties to the proceeding pursuant to which the Utility’s wildfire insurance would be entirely based on self-insurance. If approved, the self-insurance would 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 match customer funded self-insurance with wildfire related liabilities as they become payable. The settlement agreement includes a 5% deductible, that is shareholder funded, on claims that are incurred each year capped at a maximum of $50 million. The parties’ motion requested a decision on the settlement by February 2023.

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

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

Cost of Capital Proceedings

2020 and 2022 Cost of Capital Applications

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

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC. The Utility also concurrently filed a motion requesting that the revenue requirement for the 2022 cost of capital be recorded in memorandum accounts to be trued-up following a final decision in this proceeding. On October 28, 2021, the CPUC ruled that the Utility was required to comply with the cost of capital mechanism for 2022; if the CPUC determines that there are not extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022, the cost of capital adjustment mechanism would operate, and the return on common equity would be 9.67% and the cost of long-term debt would be 4.15%.

On September 30, 2022, the assigned ALJs issued a PD, and the assigned Commissioner issued an APD. Both the PD and the APD found that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be implemented for 2022. If adopted, the PD would open a second phase of this proceeding to determine the 2022 cost of capital, while the APD would retain the cost of capital previously authorized in the 2020 cost of capital proceeding and close this proceeding. Comments on the PD and APD were filed October 20, 2022, and reply comments were filed October 25, 2022.

For more information regarding this proceeding, see Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2023 Cost of Capital Application

On April 20, 2022, the Utility filed an application with the CPUC requesting that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023 (the “2023 cost of capital application”).

In its 2023 cost of capital application, the Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt. The Utility proposed to adopt a rate of ROE of 11% for test year 2023 and to retain the existing capital structure, which would result in a $231 million total increase above currently adopted electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage revenue requirements. The estimated revenue increase is based on the 2022 adopted electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base and does not reflect projected infrastructure investments beyond 2022.

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The following table compares the currently authorized capital structure and rates of return with those requested in the Utility’s application for 2023, as modified by a correction to the requested level of long-term debt that the Utility identified on June 27, 2022, and an update to the long-term cost of debt submitted on September 14, 2022. The Utility’s authorized rates of return for 2022 are currently subject to a separate cost of capital proceeding as described above.

	2022 Currently Authorized						2023 Requested
	Cost		Capital Structure		Weighted Cost		Cost		Capital Structure		Weighted Cost
Common Equity	10.25	%	52.00	%	5.33	%	11.00	%	52.00	%	5.72	%
Preferred Stock	5.52	%	0.50	%	0.03	%	5.52	%	0.50	%	0.03	%
Long-term Debt	4.17	%	47.50	%	1.98	%	4.31	%	47.50	%	2.05	%
Weighted Average Cost of Capital			100.00	%	7.34	%			100.00	%	7.80	%

For 2023, the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $141 million for electric generation and distribution and $54 million for gas distribution operations, assuming 2022 authorized rate base amounts from the 2020 GRC decision. The revenues for the gas transmission and storage operations would increase by approximately $36 million, assuming 2022 authorized rate base amounts from the 2019 GT&S decision. However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utility in its 2023 GRC, which is currently pending before the CPUC, the revenue requirement changes resulting from the Utility’s requested ROE may differ from the amounts reflected in the 2023 cost of capital application for the period beyond 2022.

The Utility 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 Utility included an illustrative calculation using the period March 2021 to February 2022 with an adjustment to increase the rate by 153 basis points, which would result in an estimated $69.3 million increase in recovery of short-term financing costs associated with its recent balancing and memorandum account balances. The actual revenue requirement impact of the short-term debt proposal would differ depending on the final adjustment set each year and the recorded balances in the balancing and memorandum accounts.

The cost of capital that is approved in this proceeding is expected to be effective until December 31, 2025, unless the cost of capital adjustment mechanism is triggered. (For more information on the cost of capital adjustment mechanism, see Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

On July 12, 2022, the CPUC issued a scoping memo which indicates a PD in November 2022.

2015 Gas Transmission and Storage Rate Case

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of 2011 to 2014 capital spending in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. On July 14, 2022, the CPUC approved a final decision approving a settlement agreement among the Utility and the active parties in the proceeding, which authorizes a $356.3 million revenue requirement for the period of 2015 through 2022. For more information regarding this proceeding, see Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Transmission Owner Rate Cases

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

As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50-basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Ninth Circuit Court of Appeals’ opinion.

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

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

On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation. The order would extinguish the Utility’s refund obligations that might have been required under the TO16 and TO17 rate cases had the Ninth Circuit Court of Appeals not found in the FERC’s favor. On May 2, 2022, the CPUC filed a petition for panel rehearing of the order. On May 25, 2022, the Ninth Circuit Court of Appeals issued a decision denying the request for rehearing and the request for a rehearing en banc.

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

As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion.  The forecasted network transmission rate base for 2017 was $6.7 billion.  The Utility sought a ROE of 10.9%, which included an incentive component of 50-basis points for the Utility’s continuing participation in the CAISO. 

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

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

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the third quarter of 2022 by approximately $384 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, as of September 30, 2022, the Utility had recorded approximately $240 million to Regulatory assets.

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liability for the potential refund for TO18 by $30 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding. On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

Aside from the ultimate outcome of the ROE rehearing request and the common plant allocation, the FERC’s orders in the TO18 proceeding are not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases. The ROE rehearing request will not impact the TO20 rate case. See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation and eliminating the refund obligation, and so the Utility was not obligated to make a refund to customers based on this matter. See “Transmission Owner Rate Cases for 2015 and 2016” above for a discussion of the incentive adder. As a result of the potential reduction to the TO18 revenue requirement, the Utility increased its regulatory liability for the potential refund for TO19 by $32 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding.

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

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

On March 31, 2020, the Utility filed a partial settlement with the FERC, which the FERC approved on August 17, 2020. On October 15, 2020, the Utility filed a settlement with the FERC resolving all of the remaining issues in the formula rate proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement establishes an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing to be effective on January 1, 2024.

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

Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO20 rate case.

Other Regulatory Proceedings

Application for Post-Emergence SB 901 Securitization Transaction

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

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs through securitization that is designed to be rate neutral to customers through the creation of a corresponding customer credit trust, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds.

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

In addition, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires, which the CPUC subsequently granted on May 11, 2021.

On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. The financing order authorized the issuance of bonds through the end of 2022. PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds on May 10, 2022 and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds on July 20, 2022. See Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Application for Second AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. Pursuant to an earlier financing order issued by the CPUC authorizing the Utility’s initial application for AB 1054 securitization transaction, on November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or will be incurred by the Utility from 2019 through 2022. The $1.7 billion reflects $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized will be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

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

On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which is the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility plans to securitize these expenditures later in 2022 or early 2023.

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2020-2022 Wildfire Mitigation Plan

The Utility’s 2022 WMP was submitted on February 25, 2022. 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 May 26, 2022, the OEIS issued a revision notice requiring the Utility to address 13 critical issues. The Utility responded to the revision notice on June 27, 2022, July 11, 2022, and July 26, 2022, respectively, as directed by OEIS. On October 6, 2022, OEIS issued a draft decision approving the Utility’s 2022 WMP. Public comments on the draft decision were submitted to OEIS on October 26, 2022, and reply comments are due by November 7, 2022.

Electric Integrated Resource Planning and Related Procurement

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

On June 30, 2021, the CPUC issued a mid-term reliability decision to address incremental electric system reliability needs between 2024 and 2026 due to, in part, the pending retirement of once-through-cooling natural gas plants in Southern California and the possible retirement of Diablo Canyon by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs. See section below entitled “Senate Bill 846” in Legislative and Regulatory Initiatives. The decision set procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision set the Utility’s share of the procurement at 2,302 MW of incremental net qualifying capacity.

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

OIR to Revisit Net Energy Metering Tariffs

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

On December 13, 2021, the CPUC issued a PD that would reduce the NEM subsidy for new non-California Alternate Rates for Energy Program (“CARE”) NEM customers by about 80 percent for standalone solar and about 60 percent for solar-paired storage. Commercial customer NEM subsidy would be reduced by about 35 percent. Additionally, the PD would reduce the legacy period for existing non-CARE NEM customers from 20 years to 15 years after which such customers would transition to the successor tariff. On May 9, 2022, the ALJ issued a ruling setting aside submission of the record to take comment on certain questions regarding possible alternative tariff elements and community solar. On August 25, 2022, the CPUC extended the statutory deadline in this proceeding until August 27, 2023.

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.

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The application requests a final decision by July 2023 to transfer the Utility’s non-nuclear generation assets to Pacific Generation. PG&E Corporation and the Utility have proposed to complete the potential minority ownership sale by the end of 2023.

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. 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 general orders 95 and 165 (including failure to perform inspections in compliance with general order 165 of approximately 55,000 poles in 2020) and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. 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 general order 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.

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

Subsurface Electric Ducts

On October 21, 2021, the Utility notified the CPUC of inconsistent application of the requirements to locate and mark empty subsurface electric ducts in accordance with Government Code sections 4216(k), 4216(s) and 4216.3(a)(1)(A). On December 30, 2021, the Utility submitted a corrective action plan to the SED and is implementing the plan.

LEGISLATIVE AND REGULATORY INITIATIVES

Vaccine Mandates

On September 9, 2021, President Biden issued an executive order that would require certain COVID-19 precautions for government contractors and their subcontractors, including mandatory employee vaccination. The requirements under the executive order are currently stayed in numerous states. The stay applicable to contracts performed in California was lifted as of August 26, 2022. However, it is unclear if or when the federal government intends to implement the executive order in California. The ultimate implementation of the executive order could result in w