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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM10-Q
(Mark One)
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period endedSeptember 30, 2023
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission
File
Number		Exact Name of
Registrant
as Specified
in its Charter		State or Other
Jurisdiction of
Incorporation		IRS Employer
Identification
Number
1-12609PG&E CorporationCalifornia94-3234914
1-2348Pacific Gas and Electric CompanyCalifornia94-0742640
PG&E CorporationPacific Gas and Electric Company
300 Lakeside Drive300 Lakeside Drive
Oakland,California94612Oakland, California 94612
Address of principal executive offices, including zip code
PG&E CorporationPacific Gas and Electric Company
415973-1000415973-7000
Registrant’s telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common stock, no par valuePCGThe New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 6% nonredeemablePCG-PANYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemablePCG-PBNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemablePCG-PCNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemablePCG-PDNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% series A redeemablePCG-PENYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemablePCG-PGNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemablePCG-PHNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% redeemablePCG-PINYSE American LLC
1

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 18, 2023: 
PG&E Corporation:
2,611,251,771*
Pacific Gas and Electric Company:
264,374,809
*Includes 67,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 410,000,000 shares of common stock held by Pacific Gas and Electric Company.


2

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2023
TABLE OF CONTENTS
SEC Form 10-Q Reference Number
3

4

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

5

GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2022 Form 10-KPG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2022
Form 10-Q
PG&E Corporation’s and the Utility’s joint Quarterly Report on Form 10-Q for the period ended September 30, 2023
ABAssembly Bill
ALJadministrative law judge
Amended ArticlesAmended 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
APDalternate proposed decision
AROasset retirement obligation
Bankruptcy Courtthe U.S. Bankruptcy Court for the Northern District of California
CAISOCalifornia Independent System Operator Corporation
Cal FireCalifornia Department of Forestry and Fire Protection
CEMACatastrophic Event Memorandum Account
Chapter 11Chapter 11 of Title 11 of the U.S. Code
Chapter 11 Casesthe voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Orderthe order confirming the Plan, dated as of June 20, 2020, with the Bankruptcy Court
CPPMACOVID-19 Pandemic Protections Memorandum Account
CPUCCalifornia Public Utilities Commission
CRRcongestion revenue rights
D&O Insurancedirectors and officers liability insurance
Diablo CanyonDiablo Canyon nuclear power plant
District CourtUnited States District Court for the Northern District of California
DOEUnited States Department of Energy
DOJUnited States Department of Justice
DTSCCalifornia Department of Toxic Substances Control
DWRCalifornia Department of Water Resources
EMANIEuropean Mutual Association for Nuclear Insurance
Emergence Date
July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOEPEnhanced Oversight and Enforcement Process
EPSearnings per common share
EPSSEnhanced Powerline Safety Settings
Exchange ActSecurities Exchange Act of 1934, as amended
FERCFederal Energy Regulatory Commission
FHPMAFire Hazard Prevention Memorandum Account
Fire Victim TrustThe trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be, funded
First Mortgage Bondsbonds issued pursuant to the Indenture of Mortgage, dated as of June 19, 2020, between the Utility and The Bank of New York Mellon Trust Company, N.A., as amended and supplemented
FRMMAFire Risk Mitigation Memorandum Account
GAAPU.S. Generally Accepted Accounting Principles
GOgeneral order
GRCgeneral rate case
GT&Sgas transmission and storage
HSMAHazardous Substance Memorandum Account
6

IOUsinvestor-owned utility(ies)
IRCInternal Revenue Code
IRSInternal Revenue Service
Lakeside Building300 Lakeside Drive, Oakland, California, 94612
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part I, Item 2, of this Form 10-Q
MGPmanufactured gas plants
NAVnet asset value
NEILNuclear Electric Insurance Limited
NEMnet energy metering
New SharesShares 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
NRCNuclear Regulatory Commission
OEISOffice of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OIIorder instituting investigation
OIRorder instituting rulemaking
Pacific GenerationPacific Generation LLC, a subsidiary of the Utility
PDproposed decision
PERAPublic Employees Retirement Association of New Mexico
PlanPG&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 SharesShares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan
PSPSPublic Safety Power Shutoff
Receivables Securitization ProgramThe 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
ROEreturn on equity
RTBARisk Transfer Balancing Account
RUBAResidential Uncollectibles Balancing Account
SBSenate Bill
SECUnited States Securities and Exchange Commission
Securities ActThe Securities Act of 1933, as amended
SEDSafety and Enforcement Division of the CPUC
SFGOThe Utility’s former San Francisco General Office headquarters complex
Share Exchange and
Tax Matters Agreement		Share Exchange and Tax Matters Agreement dated July 8, 2021 between PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust
ShareCoPG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV
PG&E AR Facility, LLC
TCJATax Cuts and Jobs Act of 2017
TOtransmission owner
USFSUnited States Forest Service
UtilityPacific 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)
VMBAVegetation Management Balancing Account
WEMAWildfire Expense Memorandum Account
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WGSCWildfire and Gas Safety Costs
Wildfire Fundstatewide 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
WMBAWildfire Mitigation Balancing Account
WMCEWildfire Mitigation and Catastrophic Events
WMPWildfire Mitigation Plan
WMPMAWildfire Mitigation Plan Memorandum Account

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines associated with various investigations and proceedings; forecasts of capital expenditures; forecasts of expense reduction; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “commit,” “goal,” “target,” “will,” “may,” “should,” “would,” “could,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

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

•the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service area, including the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), the wildfire that began on September 27, 2020 in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), the wildfire that began on July 13, 2021 near the Cresta Dam in the Feather River Canyon in Plumas County, California (the “2021 Dixie fire”), the wildfire that began on September 6, 2022 near Oxbow Reservoir in Placer County, California (the “2022 Mosquito fire”), and any other wildfires for which the causes have yet to be determined; the damage caused by such wildfires; the extent of the Utility’s liability in connection with such wildfires (including the risk that the Utility may be found liable for damages regardless of fault); investigations into such wildfires, including those being conducted by the CPUC; potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other enforcement agency were to bring an enforcement action in respect of any such fire; the risk that the Utility is not able to recover costs from the Wildfire Fund or other third parties or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations, and proceedings;

•the extent to which the Utility’s wildfire mitigation initiatives are effective, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; or to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; the cost of the program and the timing and outcome of any proceeding to recover such costs through rates; and any determination by OEIS that the Utility has not complied with its WMP;

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

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

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•significant changes to the electric power and gas industries driven by technological advancements, electrification, and the transition to a decarbonized economy; the impact of reductions in Utility customer demand for electricity and natural gas, driven by customer departures to community choice aggregators, direct access providers, increased competition from government-owned utilities, and legislative mandates to replace gas-fuel technologies; and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources and changing customer demand for its natural gas and electric services;

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

•the impact of severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, and other events that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the effectiveness of the Utility’s efforts to prevent, mitigate, or respond to such conditions or events; the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is able to procure replacement power; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;

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

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

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

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

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

◦privacy and cybersecurity; and

◦taxes and tax audits;

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; the Utility’s application to transfer its non-nuclear generation assets to Pacific Generation and the potential sale of a minority interest in Pacific Generation; and the transfer of ownership of the Utility’s assets to municipalities or other public entities, including as a result of the City and County of San Francisco’s valuation petition;

•whether the Utility can control its operating costs within the authorized levels of spending; whether the Utility can continue implementing the Lean operating system and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; the risks and uncertainties associated with inflation; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;
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•the outcome of current and future self-reports, investigations or other enforcement actions, or notices of violation that could be issued related to the Utility’s compliance with laws, rules, regulations, or orders applicable to its gas and electric operations; the construction, expansion, or replacement of its electric and gas facilities; electric grid reliability; audit, inspection and maintenance practices; customer billing and privacy; physical and cybersecurity protections; environmental laws and regulations; or otherwise, such as fines; penalties; remediation obligations; or the implementation of corporate governance, operational or other changes in connection with the EOEP;

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

•the risks and uncertainties associated with the resolution of the Subordinated Claims and the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing litigation, including certain indemnity obligations to current and former officers and directors, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings; the Wildfire-Related Non-Bankruptcy Claims; the purported PSPS class action filed in December 2019; and other third-party claims, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•the ability of PG&E Corporation and the Utility to securitize the remaining $1.385 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility;

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

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

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

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

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

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

•the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s workforce availability and the ability of the Utility to collect on customer receivables; and

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

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors in the 2022 Form 10-K and a detailed discussion of these matters contained in Item 7. MD&A in the 2022 Form 10-K and Item 2. in this Form 10-Q. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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

ITEM 1A. RISK FACTORS

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

PART I. FINANCIAL INFORMATION

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

OVERVIEW

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

Key Factors Affecting Financial Results

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

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

In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening. In particular, in 2022, the Utility expanded the EPSS program to all distribution lines in high fire risk areas. The Utility is also focused on undergrounding more lines each year while using economies of scale to make undergrounding more cost efficient. These initiatives have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.
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PG&E Corporation and the Utility have incurred and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. If additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on the costs of the Utility’s wildfire mitigation initiatives.

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

Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Once an ignition has occurred, the Utility is unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.

The financial impact of past wildfires is significant. As of September 30, 2023, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.025 billion, $400 million, $1.6 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, unless expressly noted otherwise, but do not include all categories of potential damages and losses.

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

Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. As of September 30, 2023, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $373 million for the 2020 Zogg fire, $527 million for the 2021 Dixie fire, and $58 million for the 2022 Mosquito fire.

If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. As of September 30, 2023, the Utility has recorded a Wildfire Fund receivable of $600 million for the 2021 Dixie fire. See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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The Utility will be permitted to recover its wildfire-related claims in excess of insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as receivables. As of September 30, 2023, the Utility has recorded receivables for regulatory recovery of $542 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information.

•The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). In addition, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” below), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded in memorandum and balancing accounts has increased. The Utility has also applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 3 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.

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

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

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors in the 2022 Form 10-K.  In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are unable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $26.6 billion and a California net operating loss carryforward of approximately $25.2 billion as of December 31, 2022.

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Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding deferred tax asset as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. On each of January 9, 2023, April 11, 2023, and July 12, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the nine months ended September 30, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 180,000,000 shares resulted in an aggregate tax benefit of $822 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Cumulatively through September 30, 2023, the Fire Victim Trust has sold 410,000,000 shares resulting in an aggregate tax benefit of approximately $1.7 billion recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

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

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,611,251,771 shares outstanding as of October 18, 2023, only 2,065,764,591 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 18, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of October 18, 2023 was 3.75% of the outstanding shares. As of October 18, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 410,000,000 shares of PG&E Corporation common stock in the aggregate and owned 67,743,590 shares.

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, 2023 and 2022. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

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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 income (loss) attributable to common shareholders for the three and nine months ended September 30, 2023 and 2022:
Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Consolidated Total$348 $456 $1,323 $1,287 
PG&E Corporation(69)(31)(193)(323)
Utility$417 $487 $1,516 $1,610 

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

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2023 and 2022.  The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings.

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

CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results.
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Three Months Ended September 30, 2023Three Months Ended September 30, 2022
Revenues/Costs:Revenues/Costs:
(in millions)That Impacted EarningsThat Did Not Impact EarningsTotal UtilityThat Impacted EarningsThat Did Not Impact EarningsTotal Utility
Electric operating revenues$3,247 $1,260 $4,507 $2,603 $1,292 $3,895 
Natural gas operating revenues1,047 334 1,381 1,137 362 1,499 
   Total operating revenues4,294 1,594 5,888 3,740 1,654 5,394 
Cost of electricity— 846 846 — 1,032 1,032 
Cost of natural gas— 158 158 — 257 257 
Operating and maintenance
2,520 616 3,136 1,771 477 2,248 
SB 901 securitization charges, net346 — 346 — — — 
Wildfire-related claims, net of recoveries(32)— (32)9 — 9 
Wildfire Fund expense219 — 219 118 — 118 
Depreciation, amortization, and decommissioning811 — 811 1,002 — 1,002 
   Total operating expenses3,864 1,620 5,484 2,900 1,766 4,666 
Operating income (loss)430 (26)404 840 (112)728 
Interest income
151 — 151 42 42 
Interest expense
(594)— (594)(458)— (458)
Other income, net
36 26 62 15 112 127 
Income before income taxes
23 — 23 439 — 439 
Income tax benefit (1)
(397)(51)
Net Income
420 490 
Preferred stock dividend requirement (1)
3 3 
Income Available for Common Shareholders
$417 $487 
(1) These items impacted earnings for the three months ended September 30, 2023 and 2022.

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Nine Months Ended September 30, 2023Nine Months Ended September 30, 2022
Revenues/Costs:Revenues/Costs:
(in millions)That Impacted EarningsThat Did Not Impact EarningsTotal UtilityThat Impacted EarningsThat Did Not Impact EarningsTotal Utility
Electric operating revenues$8,804 $3,674 $12,478 $7,893 $3,850 $11,743 
Natural gas operating revenues3,058 1,851 4,909 2,992 1,575 4,567 
   Total operating revenues11,862 5,525 17,387 10,885 5,425 16,310 
Cost of electricity— 2,040 2,040 — 2,314 2,314 
Cost of natural gas— 1,348 1,348 — 1,177 1,177 
Operating and maintenance
6,023 2,218 8,241 5,293 2,272 7,565 
SB 901 securitization charges, net908 — 908 40 — 40 
Wildfire-related claims, net of recoveries(35)— (35)153 — 153 
Wildfire Fund expense453 — 453 353 — 353 
Depreciation, amortization, and decommissioning2,885 — 2,885 2,915 — 2,915 
   Total operating expenses10,234 5,606 15,840 8,754 5,763 14,517 
Operating income (loss)1,628 (81)1,547 2,131 (338)1,793 
Interest income
401 — 401 71 — 71 
Interest expense
(1,667)— (1,667)(1,175)— (1,175)
Other income, net
129 81 210 77 338 415 
Income before income taxes
491 — 491 1,104 — 1,104 
Income tax benefit (1)
(1,035)(516)
Net Income
1,526 1,620 
Preferred stock dividend requirement (1)
10 10 
Income Available for Common Shareholders
$1,516 $1,610 
(1) These items impacted earnings for the nine months ended September 30, 2023 and 2022.

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, 2023 and 2022, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $554 million, or 15%, in the three months ended September 30, 2023, compared to the same period in 2022, primarily due to approximately $740 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below) and approximately $270 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended September 30, 2023, as compared to the same period in 2022. These increases were partially offset by decreases in miscellaneous and vegetation management-related revenues and the recognition of approximately $180 million in revenues in the three months ended September 30, 2022 related to the final decision approving $356 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its GT&S system, with no comparable revenues in 2023 (see “2015 Gas Transmission and Storage Rate Case” in Regulatory Matters in the 2022 Form 10-K).

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The Utility’s electric and natural gas operating revenues that impacted earnings increased by $977 million, or 9%, in the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to the recognition of approximately $740 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below), $585 million in revenues authorized in the 2020 WMCE proceeding (see “2020 WMCE Application” below), and $270 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the nine months ended September 30, 2023, with no comparable revenues in 2022. These increases were partially offset by decreases in miscellaneous and vegetation management-related revenues, the recognition of approximately $310 million in revenues related to the approval of the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K), and the recognition of approximately $180 million in revenues related to the final decision approving $356 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” in Regulatory Matters in the 2022 Form 10-K) in the nine months ended September 30, 2022, with no comparable revenues in 2023.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $749 million, or 42%, in the three months ended September 30, 2023, compared to the same period in 2022, primarily due to the recognition of previously deferred expenses including approximately $720 million authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below) and approximately $270 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below). These increases were partially offset by decreases in insurance costs related to the Utility’s adoption of self-insurance and vegetation management-related costs, as well as operating cost efficiencies in the three months ended September 30, 2023. Additionally, the Utility incurred $77 million in one-time charges as a result of its voluntary separation program in the three months ended September 30, 2022, with no comparable charges in 2023.

The Utility’s operating and maintenance expenses that impacted earnings increased by $730 million, or 14%, in the nine months ended September 30, 2023, compared to the same period in 2022, as a result of the recognition of previously deferred expenses including approximately $420 million authorized in the 2020 WMCE proceeding (see “2020 WMCE Application” below), approximately $720 million authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below), and approximately $270 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the nine months ended September 30, 2023. Additionally, the Utility recognized $50 million in expenses related to the Zogg Stipulation (as defined in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1) in the nine months ended September 30, 2023. These increases were partially offset by decreases in insurance costs related to the Utility’s adoption of self-insurance and vegetation management-related costs, as well as operating cost efficiencies in the nine months ended September 30, 2023. Additionally, the Utility recognized approximately $310 million of previously deferred expenses which were authorized in the 2018 CEMA proceeding (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K), $85 million in expenses related to the Kincade SED Settlement, $77 million in one-time charges as a result of its voluntary separation program, and $55 million in expenses related to the Kincade Stipulation and the Dixie Stipulation (each as defined in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K) in the nine months ended September 30, 2022, with no comparable charges in 2023.

SB 901 Securitization Charges, Net

SB 901 securitization charges, net, that impacted earnings increased by $346 million, or 100%, and $868 million, or 2170%, in the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022. In the three and nine months ended September 30, 2023, the Utility recorded charges of $346 million and $908 million, respectively, representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock, compared to charges of $0 and $40 million, respectively, in the same periods in 2022. For more information, see Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Wildfire-Related Claims, Net of Recoveries

Costs related to wildfires that impacted earnings decreased by $41 million, or 456%, in the three months ended September 30, 2023, compared to the same period in 2022. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire offset by probable recoveries through the Wildfire Fund, insurance, and WEMA in the three months ended September 30, 2023, as compared to pre-tax charges of $100 million related to the 2022 Mosquito fire, offset by $90 million of probable recoveries through insurance and the WEMA in the three months ended September 30, 2022.

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Costs related to wildfires that impacted earnings decreased $188 million, or 123%, in the nine months ended September 30, 2023, compared to the same period in 2022. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire, offset by probable recoveries through the Wildfire Fund, insurance, and WEMA in the nine months ended September 30, 2023, as compared to pre-tax charges of $150 million related to the 2019 Kincade fire and $100 million related to the 2022 Mosquito fire, offset by $97 million of probable recoveries through insurance and the WEMA in the nine months ended September 30, 2022.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense that impacted earnings increased by $101 million, or 86%, and $100 million, or 28%, in the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022, primarily due to accelerated amortization of the Wildfire Fund asset recorded in 2023 as a result of the $425 million 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 decreased by $191 million, or 19%, and $30 million, or 1% in the three and nine months ended September 30, 2023, compared to the same periods in 2022, primarily due to the final decision in the 2021 Nuclear Decommissioning Cost Triennial Proceeding and a deferral of depreciation expense pending probable recovery through the 2023 GRC.

Interest Income

Interest income that impacted earnings increased by $109 million, or 260%, and $330 million, or 465%, in the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022, primarily due to higher interest rates earned on regulatory balancing accounts.

Interest Expense

Interest expense that impacted earnings increased by $136 million, or 30%, and $492 million, or 42%, in the three and nine months ended September 30, 2023, respectively, compared to the same period in 2022, primarily due to the issuance of additional long-term debt and an increase in interest rates on variable-rate debt.

Other Income, Net

Changes to Other income, net that impact earnings are primarily driven by fluctuations in the balance of construction work in progress that impact the equity component of allowance for funds used during construction, and gains and losses on equity securities held by the customer credit trust.

Income Tax Benefit

Income tax benefit increased by $346 million and $519 million in the three and nine months ended September 30, 2023, compared to the same periods in 2022, primarily due to an increase in the tax benefit recognized related to the sale of shares in the Fire Victim Trust in the three and nine months ended September 30, 2023, compared to the same periods in 2022.

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The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Federal statutory income tax rate21.0 %21.0 %21.0 %21.0 %
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(447.9)%(4.8)%(55.5)%(10.9)%
Effect of regulatory treatment of fixed asset differences (2)
(417.4)%(34.6)%(59.8)%(32.4)%
Tax credits
(63.9)%(0.8)%(4.0)%(0.9)%
Fire Victim Trust (3)
(953.1)%— %(125.4)%(22.9)%
Other, net151.6 %7.6 %13.2 %(0.7)%
Effective tax rate(1,709.7)%(11.6)%(210.5)%(46.8)%
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA.
(3) Includes the tax benefit related to the sale of shares of stock in the Fire Victim Trust. See “Tax Matters” above and Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Utility Revenues and Costs that did not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs.  See below for more information.

Cost of Electricity

The Utility’s Cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity. The Cost of electricity decreased in the three and nine months ended September 30, 2023, compared to the same periods in 2022. These decreases were primarily the result of decreased customer demand for the Utility’s bundled electric services, higher energy sales to the CAISO, and $48 million recorded as a deduction to the Cost of electricity for income related to DWR grants as authorized by AB 180 for eligible costs incurred to support the extension of Diablo Canyon. These reductions were partially offset by increased fuel costs due to higher natural gas prices occurring in early 2023. See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for information on the DWR grants.
Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Cost of purchased power, net
$752 $879 $1,518 $2,016 
Fuel used in generation facilities94 153 522 298 
Total cost of electricity$846 $1,032 $2,040 $2,314 

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Cost of Natural Gas

The Utility’s Cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program and realized gains and losses on price risk management activities. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The Cost of natural gas decreased in the three months ended September 30, 2023, as compared to the same period in 2022 primarily due to lower natural gas prices. The Cost of natural gas increased in the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to higher natural gas prices occurring in early 2023 resulting from various factors including higher customer demand, lower storage levels, and regional pipeline constraints.
Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Cost of natural gas sold$116 $224 $1,226 $1,070 
Transportation cost of natural gas sold42 33 122 107 
Total cost of natural gas$158 $257 $1,348 $1,177 

Operating and Maintenance Expenses

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

Other Income, Net

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

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.

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

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. The collateral posting provisions for some of the Utility’s power and natural gas commodity and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions.

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The Utility’s annual cost of capital adjustment mechanism provides that in any year during the applicable cost of capital period in which the difference between (i) the average Moody’s Baa utility bond rates (as measured in the 12-month period from October of the prior year through September of the year in which the mechanism could trigger (the “Index”)) and (ii) 4.37% (based on the 2023 Cost of Capital decision) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism is triggered, to become effective on January 1 of the next year. For the period from October 1, 2022 to September 30, 2023, the Index averaged 141 basis points above the Utility’s cost of capital benchmark rate of 4.37%. On October 13, 2023, the Utility filed an advice letter indicating that the cost of capital adjustment mechanism had been triggered and requesting to increase the Utility’s ROE from 10.0% to 10.7% and its cost of long-term debt from 4.31% to 4.66%.

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

As of September 30, 2023, PG&E Corporation and the Utility had access to approximately $4.4 billion of total liquidity comprised of approximately $265 million of Utility cash, $324 million of PG&E Corporation cash and $3.8 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Arrearages Related to the COVID-19 Pandemic

The Utility continues to experience increased arrearages as a result of the COVID-19 pandemic. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, an annual cap set by the CPUC on the number of service disconnections for residential customers, and the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections.” The Utility’s accounts receivable balances over 30 days outstanding as of September 30, 2023 were approximately $1.0 billion, or $107 million lower than the balance as of December 31, 2022 and $783 million higher than the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic.

The Utility established the CPPMA for tracking costs related to the CPUC’s emergency authorization and order for the period the CPPMA was in effect. As of September 30, 2023, costs recorded to the CPPMA totaled $16 million and were reflected in Long-term regulatory assets on the Condensed Consolidated Balance Sheets. In addition to the $16 million recorded to the CPPMA, the Utility recorded approximately $450 million of under-collections from residential customers from January 1, 2023 to September 30, 2023 to the RUBA, which is expected to be recovered in 2024 and is reflected in Regulatory balancing accounts receivable on the Condensed Consolidated Balance Sheets.

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

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

Financial Resources

Equity Financings

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

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Debt Financings

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

On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.70% First Mortgage Bonds due 2053. The Utility intends to disburse or allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing eligible green projects and eligible social projects. Pending full disbursement or allocation of an amount equal to the net proceeds from this offering to finance or refinance eligible projects, the Utility expects to use the net proceeds for the repayment of borrowings outstanding under the Utility Revolving Credit Agreement.

On June 5, 2023, the Utility completed the sale of (i) $850 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.15 billion aggregate principal amount of 6.400% First Mortgage Bonds due 2033, and (iii) $500 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of $375 million aggregate principal amount of 3.25% First Mortgage Bonds due June 15, 2023 and for general purposes, including for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility used the remaining net proceeds to repay the $500 million aggregate principal amount of 4.25% First Mortgage Bonds due August 1, 2023.

Credit Facilities

As of September 30, 2023, PG&E Corporation and the Utility had $500 million and $3.3 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

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

On June 9, 2023, the Utility entered into an amendment to the Utility Receivables Securitization Program to, among other things, extend the scheduled termination date from September 30, 2024 to June 9, 2025 and increase the low end of the facility limit from $1.0 billion to $1.25 billion.

On June 22, 2023, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date to June 22, 2028 (subject to two one-year extensions at the option of the Utility), (ii) increase the maximum letter of credit sublimit to $2.0 billion, and (iii) increase the uncommitted incremental facility to up to $1.0 billion.

PG&E Corporation

On June 22, 2023, PG&E Corporation amended its existing revolving credit agreement to, among other things, extend the maturity date to June 22, 2026 (subject to two one-year extensions at the option of PG&E Corporation).

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

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Dividends

Utility

On each of December 15, 2022, February 16, 2023, and May 18, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 15, May 15, and August 15, 2023, respectively. On September 14, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on November 15, 2023, to holders of record on October 31, 2023.

On each of February 16, May 18, and September 14, 2023, the Board of Directors of the Utility declared common stock dividends of $425 million, $450 million, and $450 million, which were paid to PG&E Corporation on February 28, June 21, and September 29, 2023, respectively.

PG&E Corporation

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

Utility Cash Flows

PG&E Corporation’s condensed consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the nine months ended September 30, 2023 and 2022.

The Utility’s cash flows were as follows:
Nine Months Ended September 30,
 (in millions)20232022
Net cash provided by operating activities$4,530 $2,940 
Net cash used in investing activities(6,710)(8,173)
Net cash provided by financing activities1,991 5,304 
Net change in cash, cash equivalents, and restricted cash$(189)$71 

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, 2023, net cash provided by operating activities increased by $1.6 billion compared to the same period in 2022. The increase was primarily due to wildfire insurance premium payments of $778 million and a payment made to the Fire Victim Trust of $592 million during the nine months ended September 30, 2022, with no similar payments made in 2023.

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

•the timing and amount of costs in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, including funds available from self-insurance (see “2023 General Rate Case” in the “Regulatory Matters” section below for more information), the Wildfire Fund, and regulatory recoveries;

•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Wildfire-Related Securities Litigation” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below for more information);

•the ability of the Utility to collect on its customer arrearages resulting from the COVID-19 pandemic;

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•the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance, the Wildfire Fund (see “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1), and regulatory recoveries;

•the timing and amount of costs in connection with the 2020-2022 and 2023-2025 WMPs and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

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

•the timing and outcomes of the Utility’s 2023 GRC and other pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

Investing Activities

Net cash used in investing activities decreased by $1.5 billion during the nine months ended September 30, 2023 as compared to the same period in 2022. The decrease was primarily driven by a $1.4 billion decrease in purchases, net of proceeds, of customer credit trust investments in 2023.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the SB 901 securitization is designed to be rate neutral to customers.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $7.9 billion and $11.2 billion of capital expenditures in 2023. Additionally, future cash flows used in investing activities could be impacted by the timing and amount of contributions to the customer credit trust, including certain shareholder tax benefits, and $1.0 billion of cash to be contributed in 2024.

Financing Activities

Net cash provided by financing activities decreased by $3.3 billion during the nine months ended September 30, 2023 as compared to the same period in 2022. The decrease was primarily due to $7.5 billion in proceeds from SB 901 recovery bonds in 2022 with no similar transaction in 2023, partially offset by a $5.1 billion decrease in long-term debt repayments as compared to 2022. Additionally, the Utility’s repayments under revolving credit facilities increased $1.5 billion during the nine months ended September 30, 2023 as compared to the same period 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, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, equity contributions from PG&E Corporation, and the payments related to the lease and purchase of Oakland headquarters (see “Oakland Headquarters Lease and Purchase” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1).

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LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and in “Regulatory Matters” below that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

REGULATORY MATTERS

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

During the three months ended September 30, 2023 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

•On October 13, the Utility filed an advice letter indicating that the cost of capital adjustment mechanism had been triggered.

•On October 13, the Utility filed its TO21 rate case with the FERC proposing revisions to its formula rate.

•On October 7, SB 410 became law. SB 410 authorizes a ratemaking mechanism to recover distribution line, substation capacity, and new business investments that exceed the GRC annual authorized revenue requirements.

•On September 15, the Utility served opening testimony proposing to establish a balancing account to record and recover costs of electric distribution capacity additions and new non-residential electric distribution extension work as part of Phase 2 of the 2023 GRC.

•On September 13, the assigned ALJs issued a PD and the assigned Commissioner issued an APD in the Utility’s 2023 GRC.

•On August 10, the CPUC approved the settlement agreement for the 2021 WMCE proceeding.

•On August 10, the Utility filed an application with the CPUC seeking authorization for a third transaction to finance using securitization up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through the first quarter of 2024.

Cost Recovery Proceedings

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

In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of September 30, 2023, the Utility had recorded an aggregate amount of approximately $5.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and Microgrids Memorandum Account. Of these costs, approximately $1.7 billion was authorized for recovery and accounted for as current, and $4.1 billion was accounted for as long term as of September 30, 2023. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

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

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

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the three months ended September 30, 2023 are summarized in the following table:
ProceedingRequestStatus
2021 WMCE
Revenue requirement of approximately $1.47 billion
Partial settlement agreement to recover $721 million of revenue requirement approved August 2023. Settlement excludes VMBA’s $592 million proposed revenue requirement.
2022 WMCE
Revenue requirement of approximately $1.36 billion
Filed December 2022. Decision authorizing $1.1 billion of interim rate relief adopted June 2023.
2023 WGSCRevenue requirement of approximately $688 millionApplication filed June 2023

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2020 WMCE Application

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the “2020 WMCE application”). The recorded expenditures, which excluded amounts disallowed as a result of the CPUC’s decision in the OII into the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”), and the 2018 Camp fire, consisted of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and were incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflected work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue included amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement authorizes the Utility to recover a revenue requirement of $591 million over a 24-month amortization period beginning March 2023, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On February 2, 2023, the CPUC approved a final decision adopting the settlement agreement without modifications.

2021 WMCE Application

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

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The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings.

The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery request of the COVID-19 CEMA costs by $12 million. The $12 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.

On January 18, 2023, the Utility, The Utility Reform Network, and the Public Advocates Office of the CPUC filed a joint motion for approval of a settlement agreement, pursuant to which the Utility would receive a revenue requirement of $721 million. On August 10, 2023, the CPUC approved the settlement agreement, and the associated revenue requirement went into rates starting September 1, 2023 to be amortized over 24 months. The settlement agreement does not address $592 million recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

2022 WMCE Application

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. The costs addressed in the 2022 WMCE application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. In connection with the 2022 WMCE application, the Utility also requested interim rate relief of $1.1 billion to be recovered over 12 months beginning June 1, 2023. The remaining $224 million would be recovered after the CPUC issues a final decision. On June 8, 2023, the CPUC adopted a final decision granting the Utility’s request for interim rate relief, which went into effect July 1, 2023. See “2022 WMCE Interim Rate Relief Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On June 23, 2023, the ALJ revised the procedural schedule so that a PD will be issued by the second quarter of 2024.

Wildfire and Gas Safety Costs Recovery Application

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $749 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table:
Recorded Costs (in millions)
WMPMA
$2,095 
FRMMA
165 
Gas storage balancing account (1)
101 
In line inspection memorandum account (2)
92 
Other
45 
Total
$2,498 
(1) Includes costs for the Utility’s natural gas storage facilities, other than Gill Ranch, in excess of amounts authorized in the 2019 GT&S proceeding.
(2) Includes (i) capital expenditure costs for traditional in-line inspection upgrade projects in excess of amounts authorized in the 2019 GT&S rate case, (ii) expenses incurred for the associated initial traditional in-line inspection runs and direct examination and repair resulting from those initial runs, and (iii) costs associated with in-line inspection re-assessments.
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In connection with the WGSC application, the Utility also requested interim rate relief of $631 million to be recovered over 12 months. The remaining $105 million would be recovered after the CPUC issues a final decision.

The Utility has proposed a schedule that would call for a final decision prior to June 15, 2024.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

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

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

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the three months ended September 30, 2023 are summarized in the following table:
Rate CaseRequestStatus
2023 GRC
Revenue requirement of $15.82 billion for 2023
PD and APD issued September 2023. A final decision is expected in the fourth quarter of 2023.
2023 Cost of Capital
Increase ROE to 11% and cost of debt to 4.31%
Final decision issued December 2022, adopting a 10% ROE. Intervenor application for rehearing denied in August 2023.

2023 General Rate Case

Phase 1

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 (the “GRC period”) 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.

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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 enhanced vegetation management 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. On December 9, 2022, the Utility submitted a post-hearing reply brief. In the reply brief, the Utility updated the revenue requirement request due to the wildfire insurance settlement dated October 7, 2022 discussed below, stipulations with the parties regarding several disputed issues, and a reduction to the Utility’s forecast for wildfire system hardening mileage targets over the 2023 to 2026 rate case period.

Over the GRC period of 2023 through 2026, the Utility plans to make average annual capital investments of approximately $9.69 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

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

On September 13, 2023, the assigned ALJs issued a PD and the assigned Commissioner issued an APD on Phase 1 Tracks 1 and 2.

Track 1

The Utility would be authorized to collect in rates the approved revenue requirement increases beginning January 1, 2024 and to amortize the incremental revenue increases related to 2023 over the period of January 1, 2024 through December 31, 2026.

The following table compares the Track 1 revenue requirements that the PD and APD would authorize with the revenue requirement currently authorized for 2022 in the 2020 GRC and 2019 GT&S proceedings and the revenue requirement requested in the Utility’s application as amended and updated:
Revenue Requirement (in billions)
Year
Request (1)
PD (2)
Difference Between PD and Request
APD (2)
Difference Between APD and Request
2022 (as adopted)$12.21 $— $— $— $— 
202315.41 13.82 (1.59)13.31 (2.10)
202416.34 14.47 (1.87)14.02 (2.32)
202516.98 14.73 (2.25)14.32 (2.66)
202617.43 14.85 (2.58)14.49 (2.94)
(1) Request has been adjusted to exclude amounts related to self-insurance.
(2) Per the PD and APD, the Utility shall adjust the revenue requirements to reflect removal of certain costs pending reasonableness review as follows: for 2023, subtraction of $250 million; for 2024, subtraction of $239 million; for 2025, subtraction of $235 million; and for 2026, subtraction of $226 million.

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The key differences between the PD and the APD relate to underground and overhead system hardening and escalation. The PD would authorize funding for 200 miles of undergrounding and 1,800 miles of covered conductor for the GRC period. The APD would authorize funding for 973 miles of undergrounding and 1,027 miles of covered conductor for the GRC period. The Utility most recently had requested 2,000 miles of undergrounding and 320 miles of covered conductor for the GRC period. The PD would also grant the Utility’s requested escalation update whereas the APD would grant 25% of the increase in escalation rates.

Track 2

On July 22, 2022, the Utility submitted a request for Track 2 of the GRC proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $209 million in expenses and $129 million in capital expenditures. On January 6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

The PD and APD would each approve the settlement agreement. The settlement agreement would result in a revenue requirement of $221 million to be recovered over 2023 and 2024.

Rate Base and Capital Additions

The following table compares the weighted-average GRC rate base that the PD and APD would authorize with the weighted-average GRC rate base requested in the Utility’s application as amended and updated:
Rate Base (in billions)
Year
Request
PD
Difference Between PD and RequestAPD Difference Between APD and Request
2023$50.4 $47.3 $(3.1)$46.2 $(4.2)
202455.4 50.3 (5.1)49.0 (6.4)
202559.6 52.5 (7.1)51.1 (8.5)
202663.7 54.6 (9.1)53.5 (10.2)

The PD and APD weighted-average rate base amounts above are subject to removal of up to approximately $1.0 billion each year pending reasonableness review.

Both the PD and the APD would deny cost recovery through this GRC for a number of costs but give the Utility an opportunity to seek recovery of these costs in future proceedings to the extent they are eligible for cost recovery: capital costs of $0.9 billion associated with moving the Utility’s corporate headquarters to Oakland, California; capital costs of $1.2 billion and expense costs of $0.4 billion for rebuilding electric and gas infrastructure following the 2018 Camp fire; capital costs of $1.3 billion tracked in certain wildfire mitigation and other memorandum accounts; and capital costs of $0.5 billion for the gas advanced metering infrastructure module replacement project. These costs and the corresponding rate base have been removed from the PD and the APD with the exception of the $1.3 billion of costs tracked in certain wildfire mitigation and other memorandum accounts.

The Utility’s comments on the PD and the APD, as well as comments by other parties, were due on October 3, 2023. Reply comments were filed on October 9, 2023. The CPUC could vote on the PD and the APD as early as November 2, 2023.

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Phase 2

On September 15, 2023, the Utility served opening testimony proposing to establish a balancing account consistent with SB 410 to record and recover costs of electric distribution capacity additions and new non-residential electric distribution extension work incremental to the forecasts of the Utility’s Phase 1 2023 GRC. The Utility proposed to record to the balancing account actual capital expenditures for these programs, with recorded costs for a given year to be recovered through the following year’s rates and subject to reasonableness review in the 2027 GRC application. Costs recorded to the account would be subject to an annual cap, which is designed to effectuate an electric distribution average rate impact of no more than 2.5%, calculated based on the Utility’s adopted GRC electric distribution revenue requirement for the applicable year beginning in 2024. Based on the Utility’s proposed 2024 GRC electric revenue requirement of approximately $8.5 billion, the 2.5% cap would equate to approximately $213 million of revenue requirement and incremental capital expenditures of approximately $1.5 billion. A PD is expected in April 2024.

Cost of Capital Proceedings

2023 Cost of Capital Application

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital including ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision. See the 2022 Form 10-K.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The decision deferred consideration of the proposal to a second phase of the proceeding. On September 20, 2023, the assigned ALJ issued a ruling identifying the remaining issues to be addressed in the second phase of the proceeding and outlining a proposed process and schedule to resolve the remaining issues.

Cost of Capital Adjustment Mechanism

On October 13, 2023, the Utility filed an advice letter indicating that the cost of capital adjustment mechanism had been triggered and requesting to increase the Utility’s ROE from 10.0% to 10.7% and its cost of long-term debt from 4.31% to 4.66%.

Transmission Owner Rate Cases

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

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 TCJA on TO18 rates in January and February 2018 and (2) aspects of the rehearing order other than the TCJA. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

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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 2023 by approximately $479 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, 2023, the Utility had recorded approximately $297 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 and several other parties sought rehearing of the FERC’s determination of the base ROE finding. 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.

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 based on the FERC’s TO18 orders, including the orders on common plant, depreciation, the TCJA, and ROE. On May 18, 2023, the FERC issued an order rejecting a revised compliance filing regarding the TCJA. On June 20, 2023, the Utility filed a further compliance filing and a request for rehearing of the FERC’s order. On July 21, 2023, the FERC issued an order denying rehearing by operation of law. The Utility has filed an appeal in the D.C. Circuit Court of Appeals. The appeal has been consolidated with the other appeals from the FERC’s TO18 orders and is being held in abeyance until the FERC addresses the ROE issue on rehearing. For the TCJA issue, on September 27, 2023, the Utility submitted a request for a private letter ruling with the IRS to obtain clarification regarding the appropriate disposition of the matter. The outcome of the private letter ruling may impact the outcome of the Utility’s request for rehearing. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

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 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

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. For a discussion of the incentive adder, see “Transmission Owner Rate Cases for 2015 and 2016” in Item 7. MD&A in the 2022 Form 10-K. 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 disclosed in the 2022 Form 10-K, the Utility uses a formula rate for the costs associated with the Utility’s FERC-jurisdictional electric transmission facilities, which the FERC accepted, with May 1, 2019 as the effective date for rate changes. Pursuant to a settlement agreement, which the FERC has approved, the Utility has 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. The Utility filed a replacement rate filing (see “Transmission Owner Rate Case for 2024” below) on October 13, 2023 to be effective on January 1, 2024.

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.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.
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On October 24, 2023, the Utility filed a waiver request for certain inputs to the formula related to the cost of long-term debt and certain underwriting fees. The waiver request is pending before the FERC.

Transmission Owner Rate Case for 2024 (the “TO21” rate case)

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasts a 2024 retail electric transmission revenue requirement of $2.83 billion. The proposed amount reflects an approximately 11% decrease over the current rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see “Transmission Owner Rate Case Revenue Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1) and a potential transaction to lease entitlements associated with certain transmission assets. The Utility forecasts that it will make investments of approximately $1.22 billion and $1.43 billion for 2023 and 2024, respectively, for various capital projects to be placed in service before the end of 2024. The Utility has requested that FERC approve a 12.37% base return on equity as well as a 0.5% adder for its participation in the CAISO. The TO21 filing also addresses the Utility’s capital structure and several new issues including wildfire self-insurance recovery from transmission customers.

Other Regulatory Proceedings

2020-2022 Wildfire Mitigation Plans

On February 25, 2022, the Utility submitted the 2022 WMP. The 2022 WMP addressed the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread, and reducing the impact of PSPS events. On November 10, 2022, OEIS approved the Utility’s 2022 WMP. On December 15, 2022, the CPUC ratified OEIS’s approval.

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

2023-2025 Wildfire Mitigation Plan

On March 27, 2023, the Utility submitted the 2023-2025 WMP. The 2023-2025 WMP addresses the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment and reducing the customer impact of EPSS and PSPS events. On June 22, 2023, the OEIS issued a revision notice requiring the Utility to address eight critical issues. The Utility submitted the response to the revision notice on August 7, 2023. On September 27, 2023, the Utility submitted additional information on the revision notice response to the OEIS. The OEIS is scheduled to issue a draft decision for the 2023-2025 WMP by November 14, 2023. A final decision is expected from the OEIS by December 29, 2023.

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.

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On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

On January 18, 2023, intervenors filed an application for rehearing. On June 30, 2023, the CPUC denied the application.

On May 4, 2023, intervenors filed in the California Court of Appeal a petition for writ of review of the CPUC’s decision. On September 14, 2023, the appellate court granted review and will hold oral argument on a date to be determined.

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

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter. On January 20, 2023, the CPUC issued a scoping memo. On March 30, 2023, the ALJ modified the procedural schedule, pursuant to which a PD would be issued by January 2024. Parties filed opening briefs on September 18, 2023 and reply briefs on October 5, 2023.

On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation. On May 31, 2023, the FERC issued an order approving transfer from the Utility to Pacific Generation of FERC-jurisdictional assets.

Self-Reports to the CPUC

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

Electric Asset Inspections

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

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. As of September 30, 2023, the Utility completed the intrusive tests, and as of October 2, 2023, the Utility completed an end-to-end assessment of the wood pole test and treat program to proactively identify and address potential issues.
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The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

Order Instituting an Investigation into PG&E Corporation’s and the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the “Safety Culture OII”). The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents.

On April 13, 2023, the ALJ issued a PD that would close this proceeding but allow for the continued monitoring of the Utility’s safety culture through an advice letter process. On May 19, 2023, the CPUC issued a final order closing the proceeding and implementing the proposed advice letter process to allow for further monitoring.

Extension of Diablo Canyon Operations

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

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

The Utility expects to submit a new application for license renewal with the NRC by the end of 2023. On March 2, 2023, the NRC approved the Utility’s exemption request to allow continued operations at Diablo Canyon past the plant’s current licenses. This exemption will allow the Utility, similar to exemptions granted to other utilities, to continue operating both units at Diablo Canyon while the Utility’s license renewal application is under review.

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

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

The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with Diablo Canyon. On June 7, 2023, the California State Lands Commission approved an extension of the Utility’s lease at Diablo Canyon through October 31, 2030.

On August 15, 2023, the California State Water Resources Control Board approved the Utility’s plan for once-through cooling at Diablo Canyon.

On September 26, 2023 the California Energy Resources Conservation and Development Commission issued the draft report concluding that no suitable supply-side resources can be brought online as alternatives to Diablo Canyon’s energy and capacity output prior to the planned retirement dates in 2024 and 2025.

Application for Third 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.

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On August 10, 2023, the Utility filed an application with the CPUC seeking authorization for a third transaction to finance using securitization up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the first quarter of 2024. The $1.38 billion reflected $187 million recorded capital expenditure amounts that were approved by the CPUC in the 2020 GRC, $350 million capital expenditure amounts that were approved by the CPUC in the 2020 WMCE proceeding, and up to $843 million forecasted capital expenditure amounts pending in the 2023 GRC. These amounts were not included in the first or second securitization transactions. The final amount to be financed using securitization would be based on actual recorded and authorized capital expenditures incurred by the Utility prior to the securitization transaction and not to exceed the remaining $1.38 billion of the Utility’s AB 1054 allocation. If approved, the Utility anticipates the transaction will result in the last securitization of AB 1054 capital expenditure amounts subject to the equity rate base exclusion.

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, 2020 WMCE proceeding, and 2023 GRC revenue requirements following the issuance of the recovery bonds.

The Utility has requested a financing order be issued within 180 days after the filing of the application on August 10, 2023.

SB 884 10-Year Distribution Undergrounding Program

On September 13, 2023, the CPUC released a Staff Proposal for its SB 884 Program (the “SB 884 Proposal”). If adopted, the SB 884 Proposal would establish an expedited utility distribution undergrounding program pursuant to Public Utilities Code Section 8388.5(a). The SB 884 Proposal addresses the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and its related costs. On October 16, 2023, the OEIS issued a request for comments as part of its ongoing process to develop guidelines for its program.

The Utility anticipates that the OEIS and the CPUC will issue final SB 884 guidelines by the end of 2023 or beginning of 2024. The Utility expects to submit its SB 884 undergrounding plan to the OEIS in early 2024 before submitting its SB 884 cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.

LEGISLATIVE AND REGULATORY INITIATIVES

Inflation Reduction Act

In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the IRS have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility continue to evaluate the totality of the law, the regulations issued in connection with it, and its impact on qualifying investments.

The Inflation Reduction Act also added a new Energy Infrastructure Reinvestment (“EIR”) category to the DOE’s Clean Energy Financing Program. The Utility is seeking financing through the EIR to help fund California’s clean energy transition.

Revenue Procedure 2023-15

On April 14, 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method for determining natural gas repairs deductions for income tax purposes. PG&E Corporation and the Utility are continuing to evaluate the impact of the revenue procedure.

Senate Bill 410

On October 7, 2023, SB 410 became law. SB 410 authorizes electrical corporations to request, and requires the CPUC to approve, a ratemaking mechanism to recover distribution line, substation capacity, and new business investments that exceed the GRC annual authorized revenue requirements, up to an annual cap. Amounts recorded to the related balancing account would be reviewed for reasonableness in the following GRC.
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ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

RISK MANAGEMENT ACTIVITIES

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

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows.  The Utility uses derivative instruments only for risk mitigation purposes and not for speculative purposes.  The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments.  Some contracts are accounted for as leases.  The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate.  Credit limits and credit quality are monitored periodically.  These activities are discussed in detail in the 2022 Form 10-K.  There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the nine months ended September 30, 2023.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, contributions to the Wildfire Fund, and pension and other post-retirement benefit plans to be critical accounting policies. These policies are considered critical accounting estimates due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting estimates and their key characteristics are discussed in detail in the 2022 Form 10-K.


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ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
(Unaudited)
 Three Months Ended September 30,Nine Months Ended September 30,
 2023202220232022
Operating Revenues  
Electric$4,507 $3,895 $12,478 $11,743 
Natural gas1,381 1,499 4,909 4,567 
Total operating revenues
5,888 5,394 17,387 16,310 
Operating Expenses  
Cost of electricity846 1,032 2,040 2,314 
Cost of natural gas158 257 1,348 1,177 
Operating and maintenance3,139 2,250 8,252 7,651 
SB 901 securitization charges, net346 — 908 40 
Wildfire-related claims, net of recoveries(32)9 (35)153 
Wildfire Fund expense219 118 453 353 
Depreciation, amortization, and decommissioning811 1,002 2,885 2,915 
Total operating expenses
5,487 4,668 15,851 14,603 
Operating Income
401 726 1,536 1,707 
Interest income154 43 409 70 
Interest expense(682)(525)(1,924)(1,355)
Other income, net62 118 213 246 
Income (Loss) Before Income Taxes
(65)362 234 668 
Income tax benefit
(416)(97)(1,099)(629)
Net Income
351 459 1,333 1,297 
Preferred stock dividend requirement of subsidiary3 3 10 10 
Income Available for Common Shareholders
$348 $456 $1,323 $1,287 
Weighted Average Common Shares Outstanding, Basic2,111 1,987 2,041 1,987 
Weighted Average Common Shares Outstanding, Diluted2,140 2,132 2,138 2,132 
Net Income Per Common Share, Basic
$0.16 $0.23 $0.65 $0.65 
Net Income Per Common Share, Diluted
$0.16 $0.21 $0.62 $0.60 


See accompanying Notes to the Condensed Consolidated Financial Statements.
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PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
 (Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Net Income
$351 $459 $1,333 $1,297 
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, respectively)
— — — — 
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $0, $5, $2, and $7, respectively)
(2)(12)3 (17)
Total other comprehensive income (loss)(2)(12)3 (17)
Comprehensive Income 349 447 1,336 1,280 
Preferred stock dividend requirement of subsidiary3 3 10 10 
Comprehensive Income Available for Common Shareholders
$346 $444 $1,326 $1,270 

See accompanying Notes to the Condensed Consolidated Financial Statements.


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PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
(Unaudited)
 Balance at
 September 30, 2023December 31, 2022
ASSETS  
Current Assets  
Cash and cash equivalents$589 $734 
Restricted cash (includes $368 million and $201 million related to VIEs at respective dates)
373 213 
Accounts receivable
Customers (net of allowance for doubtful accounts of $537 million and $166 million at respective dates)
(includes $1.78 billion and $2.47 billion related to VIEs, net of allowance for doubtful accounts of $537 million and $166 million at respective dates)
2,178 2,645 
Accrued unbilled revenue (includes $1.13 billion and $1.16 billion related to VIEs at respective dates)
1,305 1,304 
Regulatory balancing accounts4,954 3,264 
Other1,179 1,624 
Regulatory assets355 296 
Inventories
Gas stored underground and fuel oil66 91 
Materials and supplies822 751 
Wildfire Fund asset450 460 
Other538 1,433 
Total current assets12,809 12,815 
Property, Plant, and Equipment  
Electric78,729 74,772 
Gas29,574 28,226 
Construction work in progress4,580 4,137 
Financing lease right of use asset and other788 19 
Total property, plant, and equipment113,671 107,154 
Accumulated depreciation(32,625)(30,946)
Net property, plant, and equipment81,046 76,208 
Other Noncurrent Assets  
Regulatory assets16,444 16,443 
Customer credit trust319 745 
Nuclear decommissioning trusts3,410 3,297 
Operating lease right of use asset625 1,311 
Wildfire Fund asset4,410 4,847 
Income taxes receivable9 9 
Other (includes noncurrent accounts receivable of $0 and $17 million related to VIEs, net of noncurrent allowance for doubtful accounts of $0 and $1 million at respective dates)
3,937 2,969 
Total other noncurrent assets29,154 29,621 
TOTAL ASSETS$123,009 $118,644 
See accompanying Notes to the Condensed Consolidated Financial Statements.
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PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
(Unaudited)
Balance at
September 30, 2023December 31, 2022
LIABILITIES AND EQUITY  
Current Liabilities  
Short-term borrowings$580 $2,055 
Long-term debt, classified as current (includes $173 million and $168 million related to VIEs at respective dates)
3,599 2,268 
Accounts payable
Trade creditors2,689 2,888 
Regulatory balancing accounts1,573 1,658 
Other805 778 
Operating lease liabilities85 231 
Financing lease liabilities254 — 
Interest payable (includes $137 million and $116 million related to VIEs at respective dates)
592 626 
Wildfire-related claims1,508 1,912 
Other3,487 3,372 
Total current liabilities15,172 15,788 
Noncurrent Liabilities  
Long-term debt (includes $10.51 billion and $10.31 billion related to VIEs at respective dates)
50,343 47,742 
Regulatory liabilities18,884 17,630 
Pension and other postretirement benefits220 231 
Asset retirement obligations5,990 5,912 
Deferred income taxes2,181 2,732 
Operating lease liabilities540 1,243 
Financing lease liabilities559 — 
Other4,736 4,291 
Total noncurrent liabilities83,453 79,781 
Equity  
Shareholders’ Equity  
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,133,508,181 and 1,987,784,948 shares outstanding at respective dates
31,041 32,887 
Treasury stock, at cost; 67,743,590 and 247,743,590 shares at respective dates
(688)(2,517)
Reinvested earnings(6,219)(7,542)
Accumulated other comprehensive loss(2)(5)
Total shareholders’ equity24,132 22,823 
Noncontrolling Interest - Preferred Stock of Subsidiary252 252 
Total equity24,384 23,075 
TOTAL LIABILITIES AND EQUITY$123,009 $118,644 

See accompanying Notes to the Condensed Consolidated Financial Statements.

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PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20232022
Cash Flows from Operating Activities  
Net income $1,333 $1,297 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning2,885 2,915 
Bad debt expense552 126 
Allowance for equity funds used during construction(123)(138)
Deferred income taxes and tax credits, net(570)53 
Wildfire Fund expense453 352 
Other328 541 
Effect of changes in operating assets and liabilities:
Accounts receivable112 (515)
Wildfire-related insurance receivable356 127 
Inventories(46)(152)
Accounts payable331 607 
Wildfire-related claims
(404)(528)
Other current assets and liabilities190 (551)
Regulatory assets, liabilities, and balancing accounts, net(246)(1,239)
Other noncurrent assets and liabilities(881)(183)
Net cash provided by operating activities4,270 2,712 
Cash Flows from Investing Activities  
Capital expenditures(7,101)(7,411)
Proceeds from sales and maturities of nuclear decommissioning trust investments1,226 2,135 
Purchases of nuclear decommissioning trust investments(1,302)(2,129)
Proceeds from sales and maturities of customer credit trust investments455 79 
Purchases of customer credit trust investments— (1,017)
Other11 25 
Net cash used in investing activities
(6,711)(8,318)
Cash Flows from Financing Activities  
Borrowings under credit facilities7,658 7,325 
Repayments under credit facilities(8,817)(7,364)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $61 and $35 at respective dates
4,690 4,265 
Repayments of long-term debt(896)(5,980)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees of $0 and $36 at respective dates
— 7,464 
Repayment of AB 1054 recovery bonds(38)— 
Repayment of SB 901 recovery bonds(67)— 
Other(74)(4)
Net cash provided by financing activities2,456 5,706 
Net change in cash, cash equivalents, and restricted cash15 100 
Cash, cash equivalents, and restricted cash at January 1947 307 
Cash, cash equivalents, and restricted cash at September 30$962 $407 
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Less: Restricted cash and restricted cash equivalents(373)(145)
Cash and cash equivalents at September 30$589 $262 

Supplemental disclosures of cash flow information  
Cash paid for:  
Interest, net of amounts capitalized$(1,761)$(1,295)
Supplemental disclosures of noncash investing and financing activities
  
Capital expenditures financed through accounts payable$1,068 $1,177 
Operating lease liabilities arising from obtaining right-of-use assets269 397 
Financing lease liabilities arising from obtaining right-of-use assets52 — 
Reclassification of operating lease liabilities to financing lease liabilities913 — 
Changes to PG&E Corporation common stock and treasury stock in connection
    with the Share Exchange and Tax Matters Agreement		(1,829)— 
Forgiveness of DWR loan for performance-based disbursements earned102 — 

See accompanying Notes to the Condensed Consolidated Financial Statements.

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PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(in millions, except share amounts)
Common StockTreasury StockReinvested
Earnings		Accumulated
Other
Comprehensive Income
(Loss)		Total
Shareholders'
Equity		Non-
controlling
Interest -
Preferred
Stock of
Subsidiary		Total
Equity
SharesAmountSharesAmount
Balance at December 31, 20221,987,784,948 $32,887 247,743,590 $(2,517)$(7,542)$(5)$22,823 $252 $23,075 
Net income— — — — 572 — 572 — 572 
Other comprehensive income— — — — — 5 5 — 5 
Common stock issued, net
7,989,135 (610)— — — — (610)— (610)
Treasury stock disposition— — (60,000,000)610 — — 610 — 610 
Stock-based compensation amortization— (63)— — — — (63)— (63)
Preferred stock dividend requirement of subsidiary
— — — — (3)— (3)— (3)
Balance at March 31, 20231,995,774,083 32,214 187,743,590 (1,907)(6,973)— 23,334 252 23,586 
Net income— — — — 410 — 410 — 410 
Common stock issued, net
67,007,576 (609)— — — — (609)— (609)
Treasury stock disposition— — (60,000,000)609 — — 609 — 609 
Stock-based compensation amortization— 23 — — — — 23 — 23 
Preferred stock dividend requirement of subsidiary
— — — — (4)— (4)— (4)
Balance at June 30, 20232,062,781,659 31,628 127,743,590 (1,298)(6,567)— 23,763 252 24,015 
Net income— — — — 351 — 351 — 351 
Other comprehensive loss— — — — — (2)(2)— (2)
Common stock issued, net
70,726,522 (610)— — — — (610)— (610)
Treasury stock disposition— — (60,000,000)610 — — 610 — 610 
Stock-based compensation amortization— 23 — — — — 23 — 23 
Preferred stock dividend requirement of subsidiary
— — — — (3)— (3)— (3)
Balance at September 30, 20232,133,508,181 $31,041 67,743,590 $(688)$(6,219)$(2)$24,132 $252 $24,384 


45

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(in millions, except share amounts)
Common StockTreasury StockReinvested
Earnings		Accumulated
Other
Comprehensive Income
(Loss)		Total
Shareholders'
Equity		Non-
controlling
Interest -
Preferred
Stock of
Subsidiary		Total
Equity
SharesAmountSharesAmount
Balance at December 31, 20211,985,400,540 $35,129 477,743,590 $(4,854)$(9,284)$(20)$20,971 $252 $21,223 
Net income— — — — 478 — 478 — 478 
Common stock issued, net
2,072,050 (407)— — — — (407)— (407)
Treasury stock disposition— — (40,000,000)407 — — 407 — 407 
Stock-based compensation amortization— 4 — — — — 4 — 4 
Preferred stock dividend requirement of subsidiary in arrears
— — — — (59)— (59)— (59)
Preferred stock dividend requirement of subsidiary
— — — — (2)— (2)— (2)
Balance at March 31, 20221,987,472,590 34,726 437,743,590 (4,447)(8,867)(20)21,392 252 21,644 
Net income— — — — 360 — 360 — 360 
Other comprehensive loss— — — — — (5)(5)— (5)
Common stock issued, net
195,630 (609)— — — — (609)— (609)
Treasury stock disposition— — (60,000,000)609 — — 609 — 609 
Stock-based compensation amortization— 24 — — — — 24 — 24 
Preferred stock dividend requirement of subsidiary
— — — — (4)— (4)— (4)
Balance at June 30, 20221,987,668,220 34,141 377,743,590 (3,838)(8,511)(25)21,767 252 22,019 
Net income— — — — 459 — 459 — 459 
Other comprehensive loss— — — — — (12)(12)— (12)
Common stock issued, net
31,865 — — — — — — — — 
Stock-based compensation amortization— 23 — — — — 23 — 23 
Preferred stock dividend requirement of subsidiary
— — — — (3)— (3)— (3)
Balance at September 30, 20221,987,700,085 $34,164 377,743,590 $(3,838)$(8,055)$(37)$22,234 $252 $22,486 


See accompanying Notes to the Condensed Consolidated Financial Statements.
46

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions)
(Unaudited)
 Three Months Ended September 30,Nine Months Ended September 30,
 2023202220232022
Operating Revenues  
Electric$4,507 $3,895 $12,478 $11,743 
Natural gas1,381 1,499 4,909 4,567 
Total operating revenues5,888 5,394 17,387 16,310 
Operating Expenses  
Cost of electricity846 1,032 2,040 2,314 
Cost of natural gas158 257 1,348 1,177 
Operating and maintenance3,136 2,248 8,241 7,565 
SB 901 securitization charges, net346 — 908 40 
Wildfire-related claims, net of recoveries(32)9 (35)153 
Wildfire Fund expense219 118 453 353 
Depreciation, amortization, and decommissioning811 1,002 2,885 2,915 
Total operating expenses
5,484 4,666 15,840 14,517 
Operating Income
404 728 1,547 1,793 
Interest income151 42 401 71 
Interest expense(594)(458)(1,667)(1,175)
Other income, net62 127 210 415 
Income Before Income Taxes
23 439 491 1,104 
Income tax benefit
(397)(51)(1,035)(516)
Net Income
420 490 1,526 1,620 
Preferred stock dividend requirement3 3 10 10 
Income Available for Common Stock
$417 $487 $1,516 $1,610 

See accompanying Notes to the Condensed Consolidated Financial Statements.

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PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
 (Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Net Income
$420 $490 $1,526 $1,620 
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, respectively)
1 — 1 1 
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $0, $5, $2, and $7, respectively)
(3)(12)3 (17)
Total other comprehensive income (loss)(2)(12)4 (16)
Comprehensive Income $418 $478 $1,530 $1,604 

See accompanying Notes to the Condensed Consolidated Financial Statements.

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PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
(Unaudited)
 Balance at
 September 30, 2023December 31, 2022
ASSETS  
Current Assets  
Cash and cash equivalents$265 $609 
Restricted cash (includes $368 million and $201 million related to VIEs at respective dates)
368 213 
Accounts receivable
Customers (net of allowance for doubtful accounts of $537 million and $166 million at respective dates)
(includes $1.78 billion and $2.47 billion related to VIEs, net of allowance for doubtful accounts of $537 million and $166 million at respective dates)
2,178 2,645 
Accrued unbilled revenue (includes $1.13 billion and $1.16 billion related to VIEs at respective dates)
1,305 1,304 
Regulatory balancing accounts4,954 3,264 
Other1,180 1,633 
Regulatory assets355 296 
Inventories
Gas stored underground and fuel oil66 91 
Materials and supplies822 751 
Wildfire Fund asset450 460 
Other537 1,421 
Total current assets12,480 12,687 
Property, Plant, and Equipment  
Electric78,729 74,772 
Gas29,574 28,226 
Construction work in progress4,580 4,137 
Financing lease right of use asset and other787 18 
Total property, plant, and equipment113,670 107,153 
Accumulated depreciation(32,624)(30,946)
Net property, plant, and equipment81,046 76,207 
Other Noncurrent Assets  
Regulatory assets16,444 16,443 
Customer credit trust319 745 
Nuclear decommissioning trusts3,410 3,297 
Operating lease right of use asset625 1,311 
Wildfire Fund asset4,410 4,847 
Income taxes receivable7 7 
Other (includes noncurrent accounts receivable of $0 and $17 million related to VIEs, net of noncurrent allowance for doubtful accounts of $0 and $1 million at respective dates)
3,795 2,834 
Total other noncurrent assets29,010 29,484 
TOTAL ASSETS$122,536 $118,378 
See accompanying Notes to the Condensed Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
(Unaudited)
 Balance at
 September 30, 2023December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY  
Current Liabilities  
Short-term borrowings$580 $2,055 
Long-term debt, classified as current (includes $173 million and $168 million related to VIEs at respective dates)
3,572 2,241 
Accounts payable
Trade creditors2,687 2,886 
Regulatory balancing accounts1,573 1,658 
Other736 747 
Operating lease liabilities85 231 
Financing lease liabilities254 — 
Interest payable (includes $137 million and $116 million related to VIEs at respective dates)
565 573 
Wildfire-related claims1,508 1,912 
Other3,194 3,067 
Total current liabilities
14,754 15,370 
Noncurrent Liabilities  
Long-term debt (includes $10.51 billion and $10.31 billion related to VIEs at respective dates)
45,758 43,155 
Regulatory liabilities18,884 17,630 
Pension and other postretirement benefits150 160 
Asset retirement obligations5,990 5,912 
Deferred income taxes2,604 3,090 
Operating lease liabilities540 1,243 
Financing lease liabilities559 — 
Other4,778 4,334 
Total noncurrent liabilities79,263 75,524 
Shareholders’ Equity  
Preferred stock258 258 
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates
1,322 1,322 
Additional paid-in capital30,120 29,280 
Reinvested earnings(3,177)(3,368)
Accumulated other comprehensive loss(4)(8)
Total shareholders’ equity28,519 27,484 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$122,536 $118,378 

See accompanying Notes to the Condensed Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20232022
Cash Flows from Operating Activities  
Net income $1,526 $1,620 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning2,885 2,915 
Bad debt expense552 126 
Allowance for equity funds used during construction(123)(138)
Deferred income taxes and tax credits, net(499)165 
Wildfire Fund expense453 352 
Other319 332 
Effect of changes in operating assets and liabilities:
Accounts receivable120 (514)
Wildfire-related insurance receivable356 127 
Inventories(46)(152)
Accounts payable293 595 
Wildfire-related claims(404)(528)
Other current assets and liabilities219 (524)
Regulatory assets, liabilities, and balancing accounts, net(246)(1,239)
Other noncurrent assets and liabilities(875)(197)
Net cash provided by operating activities4,530 2,940 
Cash Flows from Investing Activities  
Capital expenditures(7,101)(7,411)
Proceeds from sales and maturities of nuclear decommissioning trust investments1,226 2,135 
Purchases of nuclear decommissioning trust investments(1,302)(2,129)
Proceeds from sales and maturities of customer credit trust investments455 79 
Purchases of customer credit trust investments— (1,017)
Intercompany note to PG&E Corporation— 145 
Other12 25 
Net cash used in investing activities
(6,710)(8,173)
Cash Flows from Financing Activities  
Borrowings under credit facilities7,658 7,325 
Repayments under credit facilities(8,817)(7,364)
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Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $61 and $35 at respective dates
4,690 4,265 
Repayments of long-term debt(875)(5,959)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees of $0 and $36 at respective dates
— 7,464 
Repayment of AB 1054 recovery bonds(38)— 
Repayment of SB 901 recovery bonds(67)— 
Preferred stock dividends paid(10)(66)
Common stock dividends paid(1,325)(850)
Equity contribution from PG&E Corporation840 427 
Other(65)62 
Net cash provided by financing activities1,991 5,304 
Net change in cash, cash equivalents, and restricted cash(189)71 
Cash, cash equivalents, and restricted cash at January 1822 181 
Cash, cash equivalents, and restricted cash at September 30$633 $252 
Less: Restricted cash and restricted cash equivalents(368)(145)
Cash and cash equivalents at September 30$265 $107 

Supplemental disclosures of cash flow information  
Cash paid for:  
Interest, net of amounts capitalized$(1,496)$(1,100)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable$1,068 $1,177 
Operating lease liabilities arising from obtaining right-of-use assets269 397 
Financing lease liabilities arising from obtaining right-of-use assets52 — 
Reclassification of operating lease liabilities to financing lease liabilities 913 — 
Forgiveness of DWR loan for performance-based disbursements earned102 — 

 See accompanying Notes to the Condensed Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions)
Preferred
Stock		Common
Stock		Additional
Paid-in
Capital		Reinvested
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Shareholders'
Equity
Balance at December 31, 2022$258 $1,322 $29,280 $(3,368)$(8)$27,484 
Net income— — — 626 — 626 
Other comprehensive income— — — — 6 6 
Equity contribution— — 310 — — 310 
Common stock dividend— — — (425)— (425)
Preferred stock dividend requirement
— — — (3)— (3)
Balance at March 31, 2023258 1,322 29,590 (3,170)(2)27,998 
Net income— — — 480 — 480 
Equity contribution— — 250 — — 250 
Common stock dividend— — — (450)— (450)
Preferred stock dividend requirement
— — — (4)— (4)
Balance at June 30, 2023258 1,322 29,840 (3,144)(2)28,274 
Net income— — — 420 — 420 
Other comprehensive loss— — — — (2)(2)
Equity contribution— — 280 — — 280 
Common stock dividend— — — (450)— (450)
Preferred stock dividend requirement
— — — (3)— (3)
Balance at September 30, 2023$258 $1,322 $30,120 $(3,177)$(4)$28,519 

Preferred
Stock		Common
Stock		Additional
Paid-in
Capital		Reinvested
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Shareholders'
Equity
Balance at December 31, 2021$258 $1,322 $28,286 $(4,247)$(9)$25,610 
Net income— — — 530 — 530 
Other comprehensive income— — — — 1 1 
Preferred stock dividend requirement in arrears
— — — (59)— (59)
Preferred stock dividend requirement
— — — (2)— (2)
Balance at March 31, 2022258 1,322 28,286 (3,778)(8)26,080 
Net income— — — 600 — 600 
Other comprehensive loss— — — — (5)(5)
Equity contribution— — 212 — — 212 
Common stock dividend— — — (425)— (425)
Preferred stock dividend requirement— — — (4)— (4)
Balance at June 30, 2022258 1,322 28,498 (3,607)(13)26,458 
Net income— — — 490 — 490 
Other comprehensive loss— — — — (12)(12)
Equity contribution— — 215 — — 215 
Common stock dividend— — — (425)— (425)
Preferred stock dividend requirement— — — (3)— (3)
Balance at September 30, 2022$258 $1,322 $28,713 $(3,545)$(25)$26,723 

See accompanying Notes to the Condensed Consolidated Financial Statements.
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

Organization and Basis of Presentation

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.  The Utility is primarily regulated by the CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility.  PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated in consolidation.  The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information as of December 31, 2022 in the Condensed Consolidated Balance Sheets included in this quarterly report on Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2022 Form 10-K. This quarterly report on Form 10-Q should be read in conjunction with the 2022 Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. 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. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

54

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

The following table presents the Utility’s revenues disaggregated by type of customer:
Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Electric
Revenue from contracts with customers
   Residential$2,052 $2,128 $4,745 $4,834 
   Commercial1,818 1,711 4,245 4,135 
   Industrial579 534 1,307 1,206 
   Agricultural628 777 1,097 1,477 
   Public street and highway lighting22 20 61 57 
   Other, net (1)
459 115 381 26 
      Total revenue from contracts with customers - electric5,558 5,285 11,836 11,735 
Regulatory balancing accounts (2)
(1,051)(1,390)642 8 
Total electric operating revenue$4,507 $3,895 $12,478 $11,743 
Natural gas
Revenue from contracts with customers
   Residential$326 $392 $2,900 $2,243 
   Commercial120 162 822 703 
   Transportation service only364 356 1,206 1,111 
   Other, net (1)
21 16 (389)(251)
      Total revenue from contracts with customers - gas831 926 4,539 3,806 
Regulatory balancing accounts (2)
550 573 370 761 
Total natural gas operating revenue1,381 1,499 4,909 4,567 
Total operating revenues$5,888 $5,394 $17,387 $16,310 
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(2) These amounts represent revenues authorized to be billed or refunded to customers.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of September 30, 2023, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

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

55

During the three and nine months ended September 30, 2023, expected credit losses of $259 million and $552 million, respectively, were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables. For the three and nine months ended September 30, 2022, expected credit losses were $50 million and $126 million, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of September 30, 2023, the RUBA current balancing accounts receivable balance was $450 million, and CPPMA and FERC long-term regulatory asset balances were $5 million and $70 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 10 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of September 30, 2023, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Government Assistance

PG&E Corporation and the Utility received various government assistance programs during the nine months ended September 30, 2023. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the three and nine months ended September 30, 2023, the Condensed Consolidated Statements of Income reflected $48 million recorded as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE’s Civil Nuclear Credit Program” below). Under the loan agreement, the DWR pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of Diablo Canyon. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million.

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The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of September 30, 2023, the Condensed Consolidated Financial Statements reflected $210 million in Long-term debt. During the three and nine months ended September 30, 2023, the Condensed Consolidated Statements of Income reflected $50 million and $102 million, respectively, as a deduction to Operating and maintenance expense for income related to government grants for performance-based disbursements.

U.S. DOE’s Civil Nuclear Credit Program

On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (see “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income related to government grants. During the three and nine months ended September 30, 2023, the Condensed Consolidated Statements of Income reflected $72 million and $106 million, respectively, as a deduction to Operating and maintenance expense for income related to government grants for incurred eligible costs to support the extension of Diablo Canyon.

Variable Interest Entities

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

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Condensed Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the nine months ended September 30, 2023 or is expected to be provided in the future that was not previously contractually required. As of September 30, 2023 and December 31, 2022, the SPV had net accounts receivable of $2.9 billion and $3.6 billion, respectively, and outstanding borrowings of $1.5 billion and $1.2 billion, respectively, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the first and second AB 1054 securitization transactions, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate Recovery Property.

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PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the nine months ended September 30, 2023 or is expected to be provided in the future that was not previously contractually required. As of September 30, 2023 and December 31, 2022, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the nine months ended September 30, 2023 or is expected to be provided in the future that was not previously contractually required. As of September 30, 2023 and December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.4 billion and $7.5 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets. For more information, see Note 5 below.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs as of September 30, 2023, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs as of September 30, 2023, it did not consolidate any of them.

The Lakeside Building

BA2 300 Lakeside LLC, a wholly owned subsidiary of TMG Bay Area Investments II, LLC, and the Utility are parties to an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building which serves as the Utility’s principal administrative headquarters.

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property. The Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC as it does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to the issued letter of credit as well as the amounts it pays for base rent and certain costs, per the office lease agreement. For more information, see “Oakland Headquarters Lease and Purchase” in Note 11 below.

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Contributions to the Wildfire Fund Established Pursuant to AB 1054

PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.

PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and as required by additional information. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire.

As of September 30, 2023, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $941 million in Other non-current liabilities, $450 million in Current assets - Wildfire Fund asset, and $4.4 billion in Non-current assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended September 30, 2023 and 2022, the Utility recorded amortization and accretion expense of $219 million and $118 million, respectively. During the nine months ended September 30, 2023 and 2022, the Utility recorded amortization and accretion expense of $453 million and $353 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. As of September 30, 2023, PG&E Corporation and the Utility had recorded $600 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Wildfire Fund under AB 1054” in Note 10 below.

Pension and Other Post-Retirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2023 and 2022 were as follows:
Pension BenefitsOther Benefits
Three Months Ended September 30,
(in millions)2023202220232022
Service cost for benefits earned (1)
$94 $144 $10 $15 
Interest cost228 173 18 13 
Expected return on plan assets(245)(297)(33)(32)
Amortization of prior service cost(1)(1)1 2 
Amortization of net actuarial (gain) loss 1 — (5)(10)
Net periodic benefit cost77 19 (9)(12)
Regulatory account transfer (2)
6 64 — — 
Total$83 $83 $(9)$(12)
(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

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Pension BenefitsOther Benefits
Nine Months Ended September 30,
(in millions)2023202220232022
Service cost for benefits earned (1)
$284 $432 $29 $46 
Interest cost685 519 55 40 
Expected return on plan assets(736)(892)(99)(97)
Amortization of prior service cost(3)(3)2 5 
Amortization of net actuarial (gain) loss 1 1 (14)(30)
Net periodic benefit cost231 57 (27)(36)
Regulatory account transfer (2)
19 191 — — 
Total$250 $248 $(27)$(36)
(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) consisted of the following:
Pension
Benefits		Other
Benefits		Customer Credit TrustTotal
(in millions, net of income tax)Three Months Ended September 30, 2023
Beginning balance$(12)$18 $(1)$5 
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $0, respectively)
— — (2)(2)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $1 and $0, respectively)
(1)— — (1)
Amortization of net actuarial gain (net of taxes of $0, $2 and $0, respectively)
1 (3)— (2)
Regulatory account transfer (net of taxes of $0, $1 and $0, respectively)
— 3 — 3 
Net current period other comprehensive loss— — (2)(2)
Ending balance$(12)$18 $(3)$3 
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.

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Pension BenefitsOther
Benefits		Customer Credit TrustTotal
(in millions, net of income tax)Three Months Ended September 30, 2022
Beginning balance$(33)$18 $(5)$(20)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $5, respectively)
— — (12)(12)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $0 and $0, respectively)
— 2 — 2 
Amortization of net actuarial gain (net of taxes of $0, $2 and $0, respectively)
— (8)— (8)
Regulatory account transfer (net of taxes of $1, $2 and $0, respectively)
— 6 — 6 
Net current period other comprehensive loss— — (12)(12)
Ending balance$(33)$18 $(17)$(32)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.

Pension
Benefits		Other
Benefits		Customer Credit TrustTotal
(in millions, net of income tax)Nine Months Ended September 30, 2023
Beginning balance$(12)$18 $(6)$— 
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0 and $2, respectively)
— — 3 3 
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $1 and $0, respectively)
(2)1 — (1)
Amortization of net actuarial gain (net of taxes of $0, $4 and $0, respectively)
1 (10)— (9)
Regulatory account transfer (net of taxes of $1, $3 and $0, respectively)
1 9 — 10 
Net current period other comprehensive gain— — 3 3 
Ending balance$(12)$18 $(3)$3 
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.

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Pension
Benefits		Other
Benefits		Customer Credit TrustTotal
(in millions, net of income tax)Nine Months Ended September 30, 2022
Beginning balance$(33)$18 $— $(15)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $7, respectively)
— — (17)(17)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $1 and $0, respectively)
(2)4 — 2 
Amortization of net actuarial (gain) loss (net of taxes of $0, $8 and $0, respectively)
1 (22)— (21)
Regulatory account transfer (net of taxes of $1, $7 and $0, respectively)
1 18 — 19 
Net current period other comprehensive loss— — (17)(17)
Ending balance$(33)$18 $(17)$(32)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Current Regulatory Assets

As of September 30, 2023 and December 31, 2022, the Utility had current regulatory assets of $355 million and $296 million, respectively.  As of September 30, 2023, current regulatory assets included approximately $150 million of deferred depreciation, interest, and tax expense related to 2022 rate base that were determined to be probable of recovery through the 2023 GRC.

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Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:
 Balance at
(in millions)September 30, 2023December 31, 2022
Pension benefits (1)
$103 $120 
Environmental compliance costs1,216 1,193 
Utility retained generation (2)
51 86 
Price risk management150 177 
Catastrophic event memorandum account (3)
1,072 1,085 
Wildfire expense memorandum account (4)
517 439 
Fire hazard prevention memorandum account (5)
54 79 
Fire risk mitigation memorandum account (6)
24 65 
Wildfire mitigation plan memorandum account (7)
778 756 
Deferred income taxes (8)
3,275 2,730 
Insurance premium costs (9)
— 99 
Wildfire mitigation balancing account (10)
225 327 
Vegetation management balancing account (11)
1,930 2,276 
COVID-19 pandemic protection memorandum accounts (12)
16 26 
Microgrid memorandum account (13)
82 213 
Financing costs (14)
199 211 
SB 901 securitization (15)
5,252 5,378 
AROs in excess of recoveries (16)
173 120 
Other1,327 1,063 
Total long-term regulatory assets$16,444 $16,443 
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. The increase in the CEMA regulatory asset from December 31, 2022 to September 30, 2023 is primarily due to costs incurred for repair and restoration work performed related to an increase in declared winter storm events in the Utility’s service area. As of September 30, 2023 and December 31, 2022, $44 million and $44 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.
(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. Recovery of WEMA costs is subject to CPUC review and approval.
(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that were approved for recovery in the 2020 WMCE final decision.
(6) Includes incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.
(7) Includes costs associated with the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, the 2022 WMP for the period of January 1, 2022 through December 31, 2022, and the 2023 WMP for the period of January 1, 2023 through September 30, 2023. Recovery of these costs was requested in the 2022 WGSC application. Also includes the noncurrent portion of costs associated with the 2019 WMP that were approved for recovery per the 2020 WMCE final decision. Recovery of WMPMA costs is subject to CPUC review and approval.
(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(9) Represents excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.
(10) Represents costs associated with certain wildfire mitigation activities for the period of January 1, 2020 through September 30, 2023. The noncurrent balance includes costs incurred during the 12-month period ending December 31, 2020 that were approved for recovery in the 2021 WMCE final decision. The remaining balance includes costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.
(11) Includes costs associated with certain vegetation management activities for the period of January 1, 2020 through September 30, 2023. The noncurrent balance represents costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval.
(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of September 30, 2023, the Utility had recorded uncollectibles in the amount of $5 million for small business customers. The remaining $11 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
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(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.
(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization periods are reviewable and approved in the Utility’s cost of capital or other regulatory filings.
(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds are being paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 5 below.
(16) Represents the cumulative differences between ARO expenses and amounts collected through rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  See Note 9 below.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:
 Balance at
(in millions)September 30, 2023December 31, 2022
Cost of removal obligations (1)
$8,103 $7,773 
Public purpose programs (2)
1,281 1,062 
Employee benefit plans (3)
925 904 
Transmission tower wireless licenses (4)
416 430 
SFGO sale (5)
205 264 
SB 901 securitization (6)
6,333 5,800 
Wildfire self-insurance (7)
300 — 
Other1,321 1,397 
Total long-term regulatory liabilities
$18,884 $17,630 
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected through rates for expected costs to remove assets.
(2) Represents amounts collected through rates designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(3) Represents cumulative differences between incurred costs and amounts collected through rates for post-retirement medical, post-retirement life and long-term disability plans.
(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042. Of the $416 million, $291 million will be refunded to FERC-jurisdictional customers, and $125 million will be refunded to CPUC-jurisdictional customers.
(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022.
(6) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement when the Fire Victim Trust sells additional shares. See Note 5 below.
(7) Represents amounts collected through rates designated for wildfire self-insurance. See Note 10 below.

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Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:
Balance at
(in millions)September 30, 2023December 31, 2022
Electric distribution (1)
$690 $448 
Electric transmission (2)
98 96 
Gas distribution and transmission (3)
90 72 
Energy procurement (4)
1,204 684 
Public purpose programs (5)
192 358 
Fire hazard prevention memorandum account (6)
130 — 
Wildfire mitigation plan memorandum account (7)
79 — 
Wildfire mitigation balancing account (8)
67 2 
Vegetation management balancing account (9)
693 137 
Insurance premium costs (10)
107 602 
Residential uncollectibles balancing accounts (11)
450 126 
Catastrophic event memorandum account (12)
502 144 
Other652 595 
Total regulatory balancing accounts receivable$4,954 $3,264 

Balance at
(in millions)September 30, 2023December 31, 2022
Electric transmission (2)
$207 $228 
Gas distribution and transmission (3)
98 66 
Energy procurement (4)
515 428 
Public purpose programs (5)
266 272 
SFGO sale112 152 
Other375 512 
Total regulatory balancing accounts payable$1,573 $1,658 
(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.
(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases.
(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings.
(4) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities.
(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.
(6) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards which were approved for cost recovery in the 2020 WMCE final decision.
(7) The WMPMA tracks costs associated with the 2019 WMP which were approved for cost recovery in the 2020 WMCE final decision.
(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities which were authorized for cost recovery in the 2021 WMCE proceeding and the final decision granting interim rate relief in connection with the 2022 WMCE application.
(9) The VMBA tracks routine and enhanced vegetation management activities which were approved for cost recovery in the final decision granting interim rate relief in connection with the 2022 WMCE application.
(10) The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, as of September 30, 2023, and December 31, 2022 there were $0 and $48 million, respectively, in insurance premium costs recorded in Current regulatory assets.
(11) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers.
(12) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2018 CEMA and 2020 WMCE final decisions.

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

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NOTE 4: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of September 30, 2023:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facilityJune 2028$4,400 
(1)
$(455)$(647)$3,298 
Utility Receivables Securitization Program (2)
June 20251,500 
(3)
(1,500)— — 
(3)
PG&E Corporation revolving credit facilityJune 2026500 — — 500 
Total credit facilities$6,400 $(1,955)$(647)$3,798 
(1) Includes a $2.0 billion letter of credit sublimit.
(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.
(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

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

On June 9, 2023, the Utility entered into an amendment to the Utility Receivables Securitization Program to, among other things, extend the scheduled termination date from September 30, 2024 to June 9, 2025 and increase the low end of the facility limit from $1.0 billion to $1.25 billion.

On June 22, 2023, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date to June 22, 2028 (subject to two one-year extensions at the option of the Utility), (ii) increase the maximum letter of credit sublimit to $2.0 billion, and (iii) increase the uncommitted incremental facility to up to $1.0 billion.

PG&E Corporation

On June 22, 2023, PG&E Corporation amended its existing revolving credit agreement to, among other things, extend the maturity date to June 22, 2026 (subject to two one-year extensions at the option of PG&E Corporation).

Long-Term Debt Issuances and Redemptions

Utility

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

On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.70% First Mortgage Bonds due 2053. The Utility intends to disburse or allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing eligible green projects and eligible social projects. Pending full disbursement or allocation of an amount equal to the net proceeds from this offering to finance or refinance eligible projects, the Utility expects to use the net proceeds for the repayment of borrowings outstanding under the Utility Revolving Credit Agreement.

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On June 5, 2023, the Utility completed the sale of (i) $850 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.15 billion aggregate principal amount of 6.400% First Mortgage Bonds due 2033 and (iii) $500 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of $375 million aggregate principal amount of 3.25% First Mortgage Bonds due June 15, 2023 and for general corporate purposes, including for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility used the remaining net proceeds to repay the $500 million aggregate principal amount of 4.25% First Mortgage Bonds due August 1, 2023.

NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. In the context of the customer harm threshold decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 9 below). The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the nine months ended September 30, 2023.

Upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, and $1.0 billion is required to be contributed in 2024. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the three months ended September 30, 2023, the Utility recorded SB 901 securitization charges, net, of $346 million for tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (see Note 6 below) and $93 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. During the nine months ended September 30, 2023, the Utility recorded SB 901 securitization charges, net, of $908 million for tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (see Note 6 below) and $251 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion in total, as the tax benefits described above are recognized and recorded within Deferred income taxes.

The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities since December 31, 2022:

SB 901 securitization regulatory asset (in millions)
Balance at December 31, 2022
$5,378 
Amortization
(126)
Balance at September 30, 2023
$5,252 

SB 901 securitization regulatory liability (in millions)
Balance at December 31, 2022
$(5,800)
Amortization
377 
Additions(1)
(910)
Balance at September 30, 2023
$(6,333)
(1) Includes $2 million of expected returns on investments in the customer credit trust to be credited to customers.

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NOTE 6: EQUITY

Settlement of Equity Units

During 2020, PG&E Corporation issued 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 137 million and 168 million shares of PG&E Corporation common stock. The common stock received was based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contract component of each equity unit and was subject to certain adjustments as provided therein. The common stock received by these unitholders was originally valued at approximately $1.3 billion and recognized in shareholders’ equity by PG&E Corporation upon the issuance of the equity units. During the nine months ended September 30, 2023, all equity units were settled, resulting in the issuance of 137 million shares of PG&E Corporation common stock, valued at approximately $1.3 billion.

Ownership Restrictions in PG&E Corporation’s Amended Articles

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 (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,611,251,771 shares outstanding as of October 18, 2023, only 2,065,764,591 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of October 18, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of October 18, 2023 was 3.75% of the outstanding shares. At various dates throughout 2022 and during the nine months ended September 30, 2023, the Fire Victim Trust exchanged Plan Shares 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. During the nine months ended September 30, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 180,000,000 shares resulted in an aggregate tax benefit of $822 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Cumulatively through September 30, 2023, the Fire Victim Trust has sold 410,000,000 shares resulting in an aggregate tax benefit of approximately $1.7 billion recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. As of October 18, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 410,000,000 shares of PG&E Corporation common stock in the aggregate and owned 67,743,590 shares.

As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Dividends

Utility

On each of December 15, 2022, February 16, 2023, and May 18, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 15, May 15, and August 15, 2023, respectively. On September 14, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on November 15, 2023, to holders of record on October 31, 2023.
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On each of February 16, May 18, and September 14, 2023, the Board of Directors of the Utility declared common stock dividends of $425 million, $450 million, and $450 million, which were paid to PG&E Corporation on February 28, June 21, and September 29, 2023, respectively.

PG&E Corporation

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

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
Three Months Ended September 30,Nine Months Ended September 30,
(in millions, except per share amounts)2023202220232022
Income available for common shareholders$348 $456 $1,323 $1,287 
Weighted average common shares outstanding, basic2,111 1,987 2,041 1,987 
Add incremental shares from assumed conversions:
Employee share-based compensation6 8 6 8 
Equity Units23 137 91 137 
Weighted average common shares outstanding, diluted2,140 2,132 2,138 2,132 
Total income per common share, diluted$0.16 $0.21 $0.62 $0.60 

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 8: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.
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The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered.  These items are not reflected in the Condensed Consolidated Balance Sheets at fair value.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:
  Contract Volume at
Underlying ProductInstrumentsSeptember 30, 2023December 31, 2022
Natural Gas (1) (MMBtus (2))
Forwards, Futures and Swaps243,455,325 171,212,813 
 Options75,115,000 27,785,000 
Electricity (MWh)Forwards, Futures and Swaps8,464,522 10,814,728 
Options— 215,600 
 
Congestion Revenue Rights (3)
179,224,328 205,743,505 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

As of September 30, 2023, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$121 $(5)$15 $131 
Other noncurrent assets – other238 — — 238 
Current liabilities – other(85)5 2 (78)
Noncurrent liabilities – other(150)— — (150)
Total commodity risk$124 $— $17 $141 

As of December 31, 2022, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$824 $(170)$537 $1,191 
Other noncurrent assets – other306 — — 306 
Current liabilities – other(238)170 16 (52)
Noncurrent liabilities – other(177)— — (177)
Total commodity risk$715 $— $553 $1,268 

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

Some of the Utility’s derivative instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of September 30, 2023, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.


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NOTE 9: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

•Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below.  Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
 Fair Value Measurements
 
 At September 30, 2023
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$487 $— $— $— $487 
Nuclear decommissioning trusts
Short-term investments125 — — — 125 
Global equity securities1,933 — — — 1,933 
Fixed-income securities1,112 855 — — 1,967 
Assets measured at NAV— — — — 16 
Total nuclear decommissioning trusts (2)
3,170 855 — — 4,041 
Customer credit trust
Short-term investments108 — — — 108 
Global equity securities92 — — — 92 
Fixed-income securities22 97 — — 119 
Total customer credit trust
222 97 — — 319 
Price risk management instruments (Note 8)     
Electricity— 13 326 1 340 
Gas— 20 — 9 29 
Total price risk management instruments— 33 326 10 369 
Rabbi trusts     
Short-term investments98 — — — 98 
Global equity securities5 — — — 5 
Life insurance contracts— 66 — — 66 
Total rabbi trusts103 66 — — 169 
Long-term disability trust     
Short-term investments6 — — — 6 
Assets measured at NAV— — — — 110 
Total long-term disability trust6 — — — 116 
TOTAL ASSETS$3,988 $1,051 $326 $10 $5,501 
Liabilities:     
Price risk management instruments (Note 8)     
Electricity$— $29 $188 $(6)$211 
Gas— 18 — (1)17 
TOTAL LIABILITIES$— $47 $188 $(7)$228 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $631 million primarily related to deferred taxes on appreciation of investment value.

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 Fair Value Measurements
 December 31, 2022
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$658 $— $— $— $658 
Fixed-income securities— 49 — — 49 
Nuclear decommissioning trusts
Short-term investments117 — — — 117 
Global equity securities1,845 — — — 1,845 
Fixed-income securities1,094 791 — — 1,885 
Assets measured at NAV— — — — 25 
Total nuclear decommissioning trusts (2)
3,056 791 — — 3,872 
Customer credit trust
Short-term investments19 — — — 19 
Global equity securities218 — — — 218 
Fixed-income securities216 292 — — 508 
Total customer credit trust
453 292 — — 745 
Price risk management instruments (Note 8)    
Electricity— 94 432 40 566 
Gas— 604 — 327 931 
Total price risk management instruments— 698 432 367 1,497 
Rabbi trusts    
Short-term investments25 — — — 25 
Global equity securities5 — — — 5 
Fixed-income securities— 69 — — 69 
Life insurance contracts— 64 — — 64 
Total rabbi trusts30 133 — — 163 
Long-term disability trust    
Short-term investments10 — — — 10 
Assets measured at NAV— — — — 133 
Total long-term disability trust10 — — — 143 
TOTAL ASSETS$4,207 $1,963 $432 $367 $7,127 
Liabilities:    
Price risk management instruments (Note 8)    
Electricity$— $10 $233 $(20)$223 
Gas— 172 — (166)6 
TOTAL LIABILITIES$— $182 $233 $(186)$229 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $575 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the nine months ended September 30, 2023 and 2022.

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Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets, customer credit trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds classified as Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Uncertainty Analysis

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

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Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments.  See Note 8 above.
 Fair Value at   
(in millions)At September 30, 2023Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$282 $112 Market approachCRR auction prices
$ (145.09) - 287.80 / 1.07
Power purchase agreements$44 $76 Discounted cash flowForward prices
$ 1.49 - 187.10 / 59.85
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

 Fair Value at   
(in millions)At December 31, 2022Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$305 $138 Market approachCRR auction prices
$ (145.09) - 2,724.93 / 0.89
Power purchase agreements$127 $95 Discounted cash flowForward prices
$ (6.39) - 286.75 / 78.14
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2023 and 2022, respectively:
 Price Risk Management Instruments
(in millions)20232022
Asset balance as of July 1$126 $11 
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)
12 20 
Asset balance as of September 30$138 $31 
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

 Price Risk Management Instruments
(in millions)20232022
Asset (Liability) balance as of January 1$199 $(34)
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)
(61)65 
Asset balance as of September 30$138 $31 
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of September 30, 2023 and December 31, 2022, as they are short-term in nature.

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The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
 At September 30, 2023At December 31, 2022
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount
Level 2 Fair Value
Debt (Note 4)    
PG&E Corporation
$4,379 $4,450 $4,355 $4,490 
Utility35,246 29,313 32,847 27,666 

Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:
(in millions)Amortized
Cost		Total
Unrealized
Gains		Total
Unrealized
Losses		Total Fair
Value
As of September 30, 2023
    
Nuclear decommissioning trusts    
Short-term investments$125 $— $— $125 
Global equity securities377 1,584 (12)1,949 
Fixed-income securities2,134 2 (169)1,967 
Total (1)
$2,636 $1,586 $(181)$4,041 
As of December 31, 2022    
Nuclear decommissioning trusts    
Short-term investments$117 $— $— $117 
Global equity securities413 1,468 (11)1,870 
Fixed-income securities1,991 10 (116)1,885 
Total (1)
$2,521 $1,478 $(127)$3,872 
(1) Represents amounts before deducting $631 million and $575 million as of September 30, 2023 and December 31, 2022, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)September 30, 2023
Less than 1 year$3 
1–5 years636 
5–10 years463 
More than 10 years865 
Total maturities of fixed-income securities$1,967 

The following table provides a summary of activity for the fixed-income and equity securities:
Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Proceeds from sales and maturities of nuclear decommissioning trust investments$475 $766 $1,226 $2,135 
Gross realized gains on securities30 21 72 158 
Gross realized losses on securities(15)(40)(33)(105)

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Customer Credit Trust

The following table provides a summary of equity securities and available-for-sale debt securities:
(in millions)Amortized
Cost		Total
Unrealized
Gains		Total
Unrealized
Losses		Total Fair
Value
As of September 30, 2023
Customer credit trust
Short-term investments$108 $— $— $108 
Global equity securities82 13 (3)92 
Fixed-income securities123 — (4)119 
Total
$313 $13 $(7)$319 
As of December 31, 2022    
Customer credit trust    
Short-term investments$19 $— $— $19 
Global equity securities219 13 (14)218 
Fixed-income securities516 — (8)508 
Total
$754 $13 $(22)$745 

The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)September 30, 2023
Less than 1 year$— 
1–5 years31 
5–10 years27 
More than 10 years61 
Total maturities of fixed-income securities$119 

The following table provides a summary of activity for the fixed-income and equity securities:
Three Months Ended September 30,Nine Months Ended September 30,
(in millions)2023202220232022
Proceeds from sales and maturities of customer credit trust investments$151 $79 $455 $79 
Gross realized gains on securities9 817 8
Gross realized losses on securities (1)
(6)(18)(16)(18)
(1) Includes $4 million and $7 million of impaired debt securities which were written down to their respective fair values during the nine months ended September 30, 2023 and the three and nine months ended September 30, 2022, respectively.

NOTE 10: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate.

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Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their transmission lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

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Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

As of October 18, 2023, PG&E Corporation and the Utility are aware of approximately 125 complaints on behalf of at least 2,870 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 28, 2023, the court scheduled a new trial date for August 26, 2024.

In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022. On August 8, 2023, PG&E Corporation and the Utility entered an agreement with Cal Fire to resolve its claims arising from the 2019 Kincade fire.

On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022.

On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.025 billion as of December 31, 2022 (before available insurance). The aggregate liability remained unchanged as of September 30, 2023.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

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The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2022.
Loss Accrual (in millions)
Balance at December 31, 2022
$650 
Accrued Losses— 
Payments
(274)
Balance at September 30, 2023
$376 

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of September 30, 2023, the Utility recorded an insurance receivable for the full amount of $430 million.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged.

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

On September 24, 2021, the Shasta County District Attorney’s Office (“Shasta D.A.”) charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 24, 2023, the Utility filed a motion to set aside 10 of the remaining 11 counts. On April 14, 2023, the court issued a written tentative ruling dismissing nine of the remaining counts and inviting the parties to submit additional briefing on the issues discussed in the tentative ruling. On May 31, 2023, the Utility and the Shasta D.A. filed a civil stipulated judgment (the “Zogg Stipulation”) for the Shasta D.A. to dismiss with prejudice all criminal charges against the Utility in connection with the 2020 Zogg fire. On May 31, 2023, the Shasta County Superior Court granted the Shasta D.A.’s motion to dismiss the pending criminal charges. Subject to the terms and conditions of the Zogg Stipulation, the Utility agreed to (1) pay a total of $50 million, which will not be recoverable through rates; (2) take certain wildfire mitigation actions consistent with its then-applicable wildfire mitigation plan and (3) extend the term of the independent compliance monitor to monitor the Utility’s compliance with certain commitments in Shasta County by approximately one year. After the Zogg Stipulation was entered by the Shasta County Superior Court, the Shasta D.A. moved to dismiss the charges with prejudice, which was granted by the court on June 14, 2023. As of September 30, 2023, PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflected $46 million within Other current liabilities in connection with the Zogg Stipulation.

On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred. On May 24, 2023, the CPUC issued a resolution granting the joint motion filed by the Utility and the SED and approving the Zogg SED Settlement.

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As of October 18, 2023, PG&E Corporation and the Utility are aware of approximately 32 complaints on behalf of at least 541 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for April 8, 2024.

In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $400 million as of December 31, 2022 (before available insurance). The aggregate liability remained unchanged as of September 30, 2023.

PG&E Corporation’s and the Utility’s accrued estimated losses represent the best estimate of the liability and do not include: (i) any claims related to the Cal OES complaint, (ii) any punitive damages, or (iii) any other amounts that are not reasonably estimable.

The following table presents changes in the best estimate of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2022.
Loss Accrual (in millions)
Balance at December 31, 2022
$32 
Accrued Losses— 
Payments(19)
Balance at September 30, 2023
$13 

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of September 30, 2023, the Utility recorded an insurance receivable for $373 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $33 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.

2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

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On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

The United States Attorney’s Office for the Eastern District of California has issued a subpoena for documents. It is unclear whether the investigation is still pending. Other than the investigations that have been resolved, various entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing.

On October 9, 2023, the SED submitted for adoption by the CPUC a draft resolution approving an Administrative Consent Order and Agreement between the SED and the Utility (the “Dixie ACO”). The Dixie ACO provides that the Utility would (i) pay $2.5 million to California’s General Fund; (ii) pay $2.5 million to tribes impacted by the 2021 Dixie fire; (iii) improve its electronic recordkeeping regarding patrols and inspections of distribution facilities, at an approximate cost of $40 million over five years, and the Utility may not seek recovery of such costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2021 Dixie fire. The Dixie ACO states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. The Dixie ACO also states that the parties to it intend that nothing in it shall affect whether the Utility may obtain recovery of costs and expenses incurred in connection with the 2021 Dixie fire, including for amounts drawn from the Wildfire Fund or otherwise sought through a cost recovery application to the CPUC. The Dixie ACO will be on the agenda for the CPUC’s November 16, 2023 meeting. In connection with the Dixie ACO, PG&E Corporation and the Utility recorded a liability of $5 million reflected in Other current liabilities on the Consolidated Financial Statements for the period ended September 30, 2023. For the recordkeeping initiative costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

As of October 18, 2023, PG&E Corporation and the Utility are aware of approximately 161 complaints on behalf of at least 8,222 individual plaintiffs and a separate putative class complaint related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. On September 20, 2023, the court vacated the November 8, 2023 trial date and scheduled a new trial date for April 2, 2024. Cal Fire also filed a complaint largely repeating the allegations of the earlier Cal Fire Investigation Report and seeking damages for fire suppression and investigation costs.

On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million.

On March 2, 2023, PG&E Corporation and the Utility entered into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire.

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Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.175 billion as of December 31, 2022 (before available recoveries). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience to date in settling the claims of individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge in the third quarter of 2023 for probable losses in connection with the 2021 Dixie fire of $425 million for an aggregate liability of $1.6 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.6 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, (v) medical monitoring costs, or (vi) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2022.
Loss Accrual (in millions)
Balance at December 31, 2022
$1,131 
Accrued Losses425 
Payments(533)
Balance at September 30, 2023
$1,023 

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of September 30, 2023, the Utility recorded an insurance receivable of $527 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $373 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of September 30, 2023, the Utility recorded a Wildfire Fund receivable of $600 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. The Utility also recorded a $88 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $454 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA.

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2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near Oxbow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS and the DOJ, and PG&E Corporation and the Utility are cooperating with the investigation. PG&E Corporation and the Utility have received document and information requests from the DOJ. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is preliminary, and PG&E Corporation and the Utility do not currently have access to the evidence in the possession of the USFS, the DOJ, or other third parties.

The CPUC and other entities may also be investigating the 2022 Mosquito fire. It is uncertain when any such investigations will be complete.

As of October 18, 2023, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 233 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency, a complaint on behalf of the Middle Fork Project Finance Authority, a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency, and five complaints on behalf of the subrogation insurers. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million as of December 31, 2022 (before available insurance). The aggregate liability remained unchanged as of September 30, 2023.

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

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The Utility has liability insurance coverage for third-party liability in an aggregate amount of $733 million, with a deductible of $60 million. As of September 30, 2023, the Utility recorded an insurance receivable of $58 million for probable insurance recoveries in connection with the 2022 Mosquito fire. As of September 30, 2023, the Utility also recorded a $9 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $51 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, customers, and the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of September 30, 2023 are:
Potential Recovery Source (in millions)2022 Mosquito fire2021 Dixie fire
Insurance$58 $527 
FERC TO rates
9 88
WEMA
51 454 
Wildfire Fund— 600 
Probable recoveries at September 30, 2023 (1)
$118 $1,669 
(1) Includes legal costs.

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million. In the nine months ended September 30, 2023, the Utility commuted $207 million of the $340 million in wildfire liability insurance coverage running from $757 million to $970 million. PG&E Corporation and the Utility did not procure additional wildfire liability insurance in April 2023 as they move to a program of self-insurance. See “Self-Insurance” below.

In April 2023, the Utility purchased approximately $710 million in non-wildfire liability coverage for the period from April 1, 2023 to April 1, 2024 at a cost of approximately $167 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.

As of September 30, 2023, PG&E Corporation and the Utility had prepaid insurance of $118 million, reflected in Other current assets on the Condensed Consolidated Balance Sheets.

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

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in excess liability insurance coverage. For more information about the RTBA, see Note 3 above.

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Self-Insurance

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance once all of the Utility’s existing wildfire liability insurance policies expire, which occurred on August 1, 2023. The self-insurance is funded through CPUC-jurisdictional rates at $400 million for test year 2023 and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected through rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. The settlement agreement includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market.

Insurance Receivable

Through September 30, 2023, PG&E Corporation and the Utility recorded $430 million, $373 million, $527 million, and $58 million for probable insurance recoveries in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:
Insurance Receivable (in millions)2022 Mosquito fire2021 Dixie fire2020 Zogg fire2019 Kincade fireTotal
Balance at December 31, 2022
$45 $530 $118 $101 $794 
Accrued insurance recoveries (1)
13 (3)3 — 13 
Reimbursements
— (200)(68)(101)(369)
Balance at September 30, 2023
$58 $327 $53 $— $438 
(1) For the nine months ended September 30, 2023, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $3 million.

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [Utility’s] conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, 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 or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

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FERC TO Rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of September 30, 2023, the Utility recorded reductions of $88 million and $9 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of September 30, 2023, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $454 million and $51 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of September 30, 2023 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.7 billion based on its forecasted 2023 equity rate base, which is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 safety certification. The OEIS has set December 12, 2023 as the deadline for the Utility to file its 2023 application.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating electric IOUs for a 10-year period.

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The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

As of September 30, 2023, PG&E Corporation and the Utility recorded $600 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount due to the number of plaintiffs and the complexity of the litigation, and because a class settlement, if any, would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such settlement.

Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its then-current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases, and the litigation is now denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

Due to the commencement of the Chapter 11 Cases, the proceedings were automatically stayed as to PG&E Corporation and the Utility.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

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On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. Accordingly, the District Court administratively closed the case, subject to a motion by the parties thereto to reopen the case. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action. PERA filed its opening brief on March 6, 2023, the answering brief was filed on May 8, 2023, and PERA filed its reply on May 30, 2023. Oral argument was held on September 13, 2023.

A group of shareholders who also filed proofs of claim in the Chapter 11 Cases filed a motion to intervene in the District Court action to, among other things, oppose the lifting of the stay sought by PERA. That motion remains pending. In addition, on March 21, 2023, a sub-set of this group of shareholders filed a separate action in the United States District Court for the Northern District of California against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation. The parties stipulated to a stay and on May 16, 2023, the District Court entered an order staying the action.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from the trading of debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

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

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

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

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

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Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit. The Ninth Circuit Court of Appeals heard oral argument on May 5, 2023. On May 16, 2023, the Ninth Circuit Court of Appeals issued its decision affirming the District Court’s order. The time for appeal has expired.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations and D&O Insurance Coverage

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions and in the litigation matters enumerated under the heading “Wildfire-Related Derivative Litigation” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K. PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations.

In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants settled with certain of their D&O Insurance carriers the majority of their claims regarding, among other things, the applicability of one year of the D&O Insurance policies to the Wildfire-Related Non-Bankruptcy Securities Claims and the derivative claims described in the 2022 Form 10-K. As a result of these agreements, PG&E Corporation received insurance proceeds in an aggregate amount of $272 million. Proceeds from the D&O Insurance coverage were paid to the Fire Victim Trust for the Fire Victim Trust D&O Claims in the amount of $117 million, and PG&E Corporation intends to apply the remaining $155 million of proceeds to the Wildfire-Related Securities Claims.

PG&E Corporation and the Utility additionally may have indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases, among other things.

Butte County District Attorney’s Office Investigation into the 2018 Camp Fire

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire.

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

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to January 12, 2024.

NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve a series of complex judgments about future events.  Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation and the Utility exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  See “Purchase Commitments” below.  PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

CPUC and FERC Matters

Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in TO rate cases. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

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

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

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 liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. 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.

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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 based on the FERC’s TO18 orders, including the orders on common plant, depreciation, the TCJA, and ROE. On May 18, 2023, the FERC issued an order rejecting a revised compliance filing regarding the TCJA. On June 20, 2023, the Utility filed a further compliance filing and a request for rehearing of the FERC’s order. On July 21, 2023, the FERC issued an order denying rehearing by operation of law. The Utility has filed an appeal in the D.C. Circuit Court of Appeals. The appeal has been consolidated with the other appeals from the FERC’s TO18 orders and is being held in abeyance until the FERC addresses the ROE issue on rehearing. For the TCJA issue, on September 27, 2023, the Utility submitted a request for a private letter ruling with the IRS to obtain clarification regarding the appropriate disposition of the matter. The outcome of the private letter ruling may impact the outcome of the Utility’s request for rehearing. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up.

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 2023 by approximately $479 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $297 million to Regulatory assets.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

On October 24, 2023, the Utility filed a waiver request for certain inputs to the formula rate related to the cost of long-term debt and certain underwriting fees. The waiver request is pending before the FERC.

2022 WMCE Interim Rate Relief Subject to Refund

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as the implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. The costs addressed in the 2022 WMCE application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. In connection with the 2022 WMCE application, the Utility also requested interim rate relief of $1.1 billion to be recovered over 12 months beginning June 1, 2023. The remaining $224 million would be recovered after the CPUC issues a final decision. On June 8, 2023, the CPUC adopted a final decision granting the Utility’s request for interim rate relief, which went into effect July 1, 2023. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

On June 23, 2023, the ALJ revised the procedural schedule so that a PD will be issued by the second quarter of 2024.

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Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Accruals for contingencies related to such matters totaled $71 million and $69 million as of September 30, 2023 and December 31, 2022, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

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

On March 30, 2020, the Bankruptcy Court granted a motion to dismiss this class action by the Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend.

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the questions. The plaintiff filed its opening brief on July 1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on October 20, 2022. The Supreme Court of California heard oral argument on September 6, 2023 and is expected to issue a decision on the two questions certified by the Ninth Circuit of Appeals by December 5, 2023.

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

Confirmation Order Appeals

PG&E Corporation and the Utility emerged from bankruptcy on July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including the Ad Hoc Committee of Holders of Trade Claims (the “Trade Committee”). The Trade Committee appealed the Confirmation Order’s holding, which awarded post-petition interest on general unsecured claims at the federal judgment rate of 2.59%. The Trade Committee is seeking for its members to receive post-petition interest at the rates specified under their contracts or the rate established under California state law, which is 10%. The Bankruptcy Court and the federal district court held that the Trade Committee’s members are entitled to post-petition interest at the federal judgment rate. On June 8, 2021, the Trade Committee appealed the federal district court decision to the Ninth Circuit Court of Appeals. On August 29, 2022, a three-judge panel of the Ninth Circuit Court of Appeals reversed the federal district court decision 2-1. On February 2, 2023, the Utility filed a petition for a writ of certiorari to the Supreme Court of the United States. On May 22, 2023, the Supreme Court of the United States denied the Utility’s petition.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility have recorded charges for amounts that are not material. PG&E Corporation and the Utility do not believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

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Tax Matters

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to the deductibility of approximately $850 million in repair costs for gas transmission and distribution lines and $400 million in customer bill credits, which the Utility incurred in connection with the decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. The IRS is auditing tax years 2015 through 2018.

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility have recorded charges for amounts that are not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)September 30, 2023December 31, 2022
Topock natural gas compressor station$282 $284 
Hinkley natural gas compressor station106 110 
Former MGP sites owned by the Utility or third parties (1)
837 750 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
117 112 
Fossil fuel-fired generation facilities and sites (3)
25 26 
Total environmental remediation liability$1,367 $1,282 
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.
(2) Primarily driven by geothermal landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.  The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

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The Utility’s environmental remediation liability as of September 30, 2023, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. As of September 30, 2023, the Utility expected to recover $1.13 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $229 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is conducting a background study on the site to better define the chromium plume boundaries. A background report was finalized in April 2023. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $128 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $598 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $77 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

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Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $50 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages to the site’s spent fuel storage installation. NEIL also provides coverage for damages caused by acts of terrorism and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $5 million.  For more information about the Utility’s nuclear insurance coverage, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

Purchase Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. As of December 31, 2022, the Utility had undiscounted future expected obligations of approximately $35 billion. See Note 16 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

Oakland Headquarters Lease and Purchase

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million. The term of the Lease began on April 8, 2022.

The Lease required the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility, and the process of subdividing the real estate was completed on February 6, 2023.

The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of September 30, 2023, approximately 659,000 rentable square feet of the leased premises has been made available for use by the Utility.

On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the Property, as modified. Pursuant to the Purchase and Sale and Joint Escrow Instructions, the purchase price of the Property will be $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million to be paid on or before July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. Additionally, the $75 million option payment letter of credit was returned to the Utility. The Utility will also receive a credit of approximately $172 million towards the final payment, subject to adjustments, which represents the estimated outstanding principal balance of a loan carried by the Property that will be assigned to, and assumed by, the Utility at closing. The Utility will continue to lease the Property pursuant to the Lease, as amended, until closing.

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The execution of the Amendment to Office Lease Agreement on July 11, 2023 triggered a modification of the Lease, which resulted in the Lease being remeasured and reclassified from an operating lease to a financing lease during the quarter ended September 30, 2023.

As of September 30, 2023, the Utility has recorded $787 million in Financing lease right of use assets, $130 million in accumulated amortization, $237 million in leasehold improvements, which includes $156 million that was provided to the Utility as lease incentives, $254 million in current Financing lease liabilities, and $559 million in noncurrent Financing lease liabilities in the Condensed Consolidated Financial Statements primarily related to the Lease, as amended.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices.  PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only.  Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates.  See the section above entitled “Risk Management Activities” in MD&A and in Notes 8 and 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, 2023, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Exchange Act, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 2023, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business.  For more information regarding material lawsuits and proceedings, including updates to information reported under Item 3 Legal Proceedings of the 2022 Form 10-K, see Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, MD&A: “Litigation Matters.”

Each of PG&E Corporation and the Utility has elected to disclose environmental proceedings described in Item 103(c)(3)(iii) of Regulation S- K unless it reasonably believes that such proceeding will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than $1 million.

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

Share Exchanges

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. On each of January 9, 2023, April 11, 2023, and July 12, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. As of September 30, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 410,000,000 shares of PG&E Corporation common stock in the aggregate.
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Each exchange was effected in reliance on the exemption from registration under Section 3(a)(10) of the Securities Act. See “Tax Matters” in Part I, MD&A above and “Share Exchange and Tax Matters Agreement” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2021 for a detailed discussion of the exchange and the terms of the Share Exchange and Tax Matters Agreement, respectively.

ITEM 5. OTHER INFORMATION

On June 7, 2023, Cheryl F. Campbell, who serves as a non-employee director on each of PG&E Corporation’s and the Utility’s Boards of Directors and is Chair of the Utility’s Board of Directors, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c), for the sale of up to 10,000 shares of PG&E Corporation common stock. The trading arrangement terminated on the execution of the sale of all 10,000 shares on September 12, 2023.

Certain officers have made elections to participate in, and are participating in, the PG&E Corporation Retirement Savings Plan (the 401(k) plan), which includes a PG&E Corporation Common Stock Fund investment option, and non-qualified deferred compensation plans, which may have a similar option and are described in PG&E Corporation’s and the Utility’s joint proxy statement. Also, certain officers have made, and may from time to time make, elections to have shares withheld to cover withholding taxes upon the vesting of restricted stock units or performance share units, or to pay the exercise price and withholding taxes for stock options, which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).

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ITEM 6. EXHIBITS

EXHIBIT INDEX
3.1
3.2
3.3
3.4
10.1
10.2*
10.3*
10.4*
10.5*
10.6*
31.1**
31.2**
32.1**
32.2**
101.INSXBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION
 
/s/ CAROLYN J. BURKE
Carolyn J. Burke
Executive Vice President and Chief Financial Officer
(duly authorized officer and principal financial officer)
PACIFIC GAS AND ELECTRIC COMPANY
 
/s/ STEPHANIE N. WILLIAMS
Stephanie N. Williams
Vice President, Chief Financial Officer, and Controller
(duly authorized officer and principal financial officer)

Dated: October 25, 2023
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EXHIBIT 10.2

PG&E CORPORATION
SUPPLEMENTAL RETIREMENT SAVINGS PLAN


This is the controlling and definitive statement of the PG&E CORPORATION (“PG&E CORP”) Supplemental Retirement Savings Plan (the “Plan”). Except as provided herein, the Plan is effective as of January 1, 2000, with respect to all individuals who were Eligible Employees as of such date. The Plan takes the place of and assumes existing benefits under the PG&E Corporation Deferred Compensation Plan for Officers, the PG&E Corporation Supplemental Executive Retirement Plan, the Savings Fund Plan Excess Benefit Arrangement of Pacific Gas and Electric Company, and any other non-qualified defined contribution retirement plan excess benefit plans, programs or practices maintained by any Participating Subsidiary of PG&E CORP. The Plan as originally adopted was effective January 1, 2000, for Eligible Employees of Pacific Gas and Electric Company and for Grandfathered Eligible Employees of PG&E CORP; it was effective January 1, 1999, for Eligible Employees of PG&E Generating Company; and it was effective January 1, 1997, for all other Eligible Employees of PG&E CORP. The Plan as amended herein is effective September 19, 2001. The Plan is frozen as to amounts “deferred” within the meaning of Code Section 409A after December 31, 2004. The Plan was amended effective September 12, 2023, to add claims and appeals procedures.
1.    Purpose of the Plan.
The Plan is established and is maintained for the benefit of a select group of management and highly compensated employees of PG&E CORP and its Participating Subsidiaries in order to provide such employees with certain deferred compensation benefits. The Plan is an unfunded deferred compensation plan that is intended to qualify for the exemptions provided in Sections 201, 301, and 401 of ERISA.
2.    Definitions.
The following words and phrases shall have the following meanings unless a different meaning is plainly required by the context:
(a)    “Basic Employer Contributions” shall mean the amounts credited to Eligible Employees’ Accounts under the Plan by the Employers, in accordance with Section 3(c).
(b)    “Board of Directors” shall mean the Board of Directors of PG&E CORP, as from time to time constituted.
(c)    “Code” shall mean the Internal Revenue Code of 1986, as amended. Reference to a specific section of the Code shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.
(d)    “Committee” shall mean the Nominating and Compensation Committee of the Board, as it may be constituted from time to time.
(e)    “Eligible Employee” shall mean an Employee who:
(1)    Is an officer of PG&E CORP or any Participating Subsidiary and who is in Officer Band 5 or above; or


(2)    Is a key employee of PG&E CORP or any Participating Subsidiary and who is designated by the Plan Administrator as eligible to participate in the Plan.

(f)    “Eligible Employee’s Account” or “Account” shall mean as to any Eligible Employee, the separate account maintained on the books of the Employer in accordance with Section 6(a) in order to reflect his or her interest under the Plan. Accounts shall be centrally administered by the Plan Administrator or its designee.
(g)    “Employee” shall mean an individual who is treated in the records of an Employer as an employee of the Employer, who is not on an unpaid leave of absence, and/or who is not covered by a collective bargaining agreement; provided, however, such term shall not mean an individual who is a “leased employee” or who has entered into a written contract or agreement with an Employer which explicitly excludes such individual from participation in an Employer’s benefit plans. The provisions of this definition shall govern, whether or not it is determined that an individual otherwise meets the definition of “common law” employee.
(h)    “Employers” shall mean PG&E CORP and the Participating Subsidiaries designated by the Employee Benefit Committee of PG&E CORP. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan.
(i)    “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. Reference to a specific section of ERISA shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.
(j)    “Grandfathered” shall mean an individual who was an Employee of Pacific Gas and Electric Company and who has become an Employee of PG&E CORP by reason of a transfer prior to January 1, 2000.
(k)    “Investment Funds” shall mean (i) the PG&E CORP Phantom Stock Fund, (ii) the AA Utility Bond Fund, and (iii) the S&P 500 Index Fund. The Investment Funds shall be used for tracking phantom investment results under the Plan.
(l)    “Matching Employer Contributions” shall mean the amounts credited to Eligible Employees’ Accounts under the Plan by the Employers, in accordance with Section 3(b).
(m)    “Participating Subsidiary” shall mean a United States-based subsidiary of PG&E CORP, which has been designated by the Employee Benefit Committee of PG&E CORP as a Participating Subsidiary under this Plan. At such times and under such conditions as the Committee may direct, one or more other subsidiaries of PG&E CORP may become Participating Subsidiaries or a Participating Subsidiary may be withdrawn from the Plan. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan.
(n)    “PG&E CORP” shall mean PG&E Corporation, a California corporation.
(o)    “Plan” shall mean the PG&E Corporation Supplemental Retirement Savings Plan, as set forth in this instrument and as heretofore and hereafter amended from time to time.
    -2-

(p)    “Plan Year” shall mean the calendar year.
(q)    “Retirement” or “Retire” shall mean an Eligible Employee’s “separation from service” within the meaning of Section 401(k) of the Code, provided that the Eligible Employee is at least 55 years of age and has been employed by an Employer for at least five years.
(r)    “RSP” shall mean, with respect to any Eligible Employee, the PG&E Corporation Retirement Savings Plan or any predecessor qualified retirement plan sponsored by PG&E CORP or any of its subsidiary companies.
(s)    “Valuation Date” shall mean:
(1)    For purposes of valuing Plan assets and Eligible Employees’ Accounts for periodic reports and statements, the date as of which such reports or statements are made; and
(2)    For purposes of determining the amount of assets actually distributed to the Eligible Employee, his or her beneficiary, or an Alternate Payee (or available for withdrawal), a date that shall not be more than seven business days prior to the date the check is issued to the Eligible Employee.
In any other case, the Valuation Date shall be the date designated by the Plan Administrator (in its discretion) or the date otherwise set forth in this Plan. In all cases, the Plan Administrator (in its discretion) may change the Valuation Date, on a uniform and nondiscriminatory basis, as is necessary or appropriate. Notwithstanding the foregoing, the Valuation Date shall occur at least annually.
3.    Employer Contributions.
(a)    Matching Employer Contributions. Subject to the provisions of Section 13, the Eligible Employee’s Account shall be credited for each Plan Year with a Matching Employer Contribution, calculated in the manner provided in Sections 3(a) (1), (2), and (3) below:
(1)    First, an amount shall be calculated equal to the maximum matching contribution that would be made under the terms of the RSP, taking into account for such Plan Year the amount of pre-tax deferrals and after-tax contributions the Eligible Employee elected under the RSP. For purposes of this calculation, any amounts deferred under Subsection 4(a) of this Plan shall be treated as pre-tax deferrals under the RSP.
(2)    The calculation made in accordance with this Section 3(a) (1) above shall be made without regard to any limitation on such amounts under the RSP resulting from the application of any of the limitations under Code Sections 401(m), 401(a)(17), or 415.
(3)    The Employer Matching Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(a) (1) and (2) above, reduced by the amount of matching contribution made to such Eligible Employee’s account for such Plan Year under the RSP.

    -3-

(b)    Crediting of Matching Employer Contributions. Matching Employer Contributions shall be calculated and credited to the Eligible Employee’s Account as of the first business day of the calendar year following the Plan Year and shall be credited only if the Eligible Employee is an Employee on the last day of Plan Year for which the amounts are credited.
(c)    Basic Employer Contributions. Subject to the provisions of Section 13, the Account of each Eligible Employee shall be credited for each Plan Year with a Basic Employer Contribution, calculated in the manner provided in Sections 3(c) (1), (2), and (3) below:

(1)    First, an amount shall be calculated equal to the Basic Employer Contribution that would be made under the terms of the RSP, taking into account for such Plan Year the Eligible Employee’s Covered Compensation under the RSP, before any deductions for compensation deferrals elected by such Eligible Employee under Subsection 4(a) of this Plan. For Eligible Employees as defined by Section 2(e)(1) of this Plan, compensation shall also reflect such Eligible Employee’s Short-Term Incentive Plan awards.
(2)    The calculation made in accordance with this Section 3(c)(1) above shall be made without regard to any limitation on such amounts under the RSP resulting from the application of any of the limitations under Code Sections 401(a)(4), 401(a)(17), or 415.
(3)    The Employer Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(c)(1) and (2) above, reduced by the amount of Basic Employer Contributions made to such Eligible Employee’s account for such Plan Year under the RSP.
(d)    Crediting of Basic Employer Contributions. The Employer Contribution attributable to an Eligible Employee’s Short Term Incentive Plan award shall be credited to an Eligible Employee’s Account as of the first business day of the month following the date on which the Short-Term Incentive Plan award is paid. All other Employer Contributions made in respect of an Eligible Employee shall be credited to the Eligible Employee’s Account as of the first business day of the calendar year following the Plan Year and shall be credited only if the Eligible Employee is an Employee on the last day of the Plan Year for which the amounts are credited.
(e)    FICA Taxes. Each Eligible Employee shall be responsible for FICA taxes on amounts credited to his or her Account under Sections 3 and 4(d).
4.    Eligible Employee Deferrals.
(a)    Amount of Deferral. An Eligible Employee may defer (i) 5 percent to 50 percent of his or her annual salary; and (ii) all or part of his or her Short Term Incentive Plan awards, Long-Term Incentive Plan (LTIP) awards (other than stock options), Perquisite Allowances, and any other special payments, awards, or bonuses as authorized by the Plan Administrator.
(b)    Credits to Accounts. Salary deferrals shall be credited to an Eligible Employee’s Account as of each payroll period. All other deferrals attributable to allowances,
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awards, bonuses, and other payments shall be credited as of the date that they otherwise would have been paid.
(c)    Deferral Election. An Eligible Employee must file an election form with the Plan Administrator which indicates the percentage of salary and applicable pay periods, and the amount of any awards, allowances, payments, and bonuses to be deferred under the Plan. Notwithstanding the foregoing, upon first becoming an Eligible Employee, an election to defer shall be effective for the month following the filing of a Deferral Election Form, provided said Form is filed within 60 days following the date when the employee first becomes an Eligible Employee.
(d)    Deferral of Special Incentive Stock Ownership Premiums. All of an Eligible Employee’s Special Incentive Stock Ownership Premiums are automatically deferred to the Plan immediately upon grant and converted into units in the PG&E CORP Phantom Stock Fund. The units attributable to Special Incentive Stock Ownership Premiums and any additional units resulting from the conversion of dividend equivalents thereon remain unvested until the earlier of the third anniversary of the date on which the Special Incentive Stock Ownership Premiums are credited to an Eligible Employee’s account (provided the Eligible Employee continues to be employed on such date), death, disability, or retirement of the participant, or upon a Change in Control as defined in the LTIP. (The term “disability” shall, for purposes of the Plan, have the same meaning as in Section 22(e)(3) of the Internal Revenue Code.) Unvested units attributable to Special Incentive Stock Ownership Premiums and any additional units resulting from the conversion of dividend equivalents thereon shall be forfeited upon termination of the Eligible Employee’s employment unless otherwise provided in the PG&E Corporation Officer Severance Policy, or if an Eligible Employee’s stock ownership falls below the levels set forth in the Executive Stock Ownership Program.
5.    Investment Funds.
(a)    Although no assets will be segregated or otherwise set aside with respect to an Eligible Employee’s Account, the amount that is ultimately payable to the Eligible Employee with respect to such Account shall be determined as if such Account had been invested in some or all of the Investment Funds. The Plan Administrator, in its sole discretion, shall adopt (and modify from time to time) such rules and procedures as it deems necessary or appropriate to implement the deemed investment of the Eligible Employees’ Accounts. Such procedures generally shall provide that an Eligible Employee’s Account shall be deemed to be invested among the three Investment Funds in the manner elected by the Eligible Employee in such percentages and manner as prescribed by the Plan Administrator. In the event no election has been made by the Eligible Employee, such Account will be deemed to be invested in the AA Utility Bond Fund. Eligible Employees shall be able to reallocate their Accounts between the Investment Funds and reallocate amounts newly credited to their Accounts at such time and in such manner as the Plan Administrator shall prescribe. Anything to the contrary herein notwithstanding, an Eligible Employee may not reallocate Account balances between Investment Funds if such reallocation would result in a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any successor to Rule 16b-3, as in effect when the reallocation is requested.
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(1)    AA Utility Bond Fund. Interest shall be credited daily on the amounts invested in the AA Utility Bond Fund. Such interest shall be at a rate equal to the AA Utility Bond Yield reported in Moody’s Public Utility, published in the issue of Moody’s Investors Service immediately preceding the day on which the interest is to be credited. Such interest shall become a part of the Eligible Employee’s Account and shall be paid at the same time or times as the balance of the Eligible Employee’s Account.
(2)    PG&E CORP Phantom Stock Fund. Amounts credited to the PG&E CORP Phantom Stock Fund shall be converted into units (including fractions computed to three decimal places) each representing a share of PG&E CORP common stock. The value of a unit for purposes of determining the number of units to credit upon initial allocation or upon reallocation from another Investment Fund, and for determining the dollar value of the aggregate number of units to be reallocated from the PG&E CORP Phantom Stock Fund to another Investment Fund and for distributions from the Plan, shall be the closing price of a share of PG&E CORP common stock as traded on the New York Stock Exchange on the date that (i) amounts are credited to an Eligible Employee’s Account in the PG&E CORP Phantom Stock Fund, or (ii) the Plan Administrator receives a reallocation request, in the case of reallocations. If such credit or reallocation occurs after close of the New York Stock Exchange on that day, the price shall be based on the closing price of a share of PG&E CORP common stock on the next day on which such shares are traded on the New York Stock Exchange. Thereafter, the value of a unit shall fluctuate in accordance with the closing price of PG&E CORP common stock on the New York Stock Exchange. Each time that PG&E CORP pays a dividend on its common stock, an amount equal to such dividend payable with respect to each share of PG&E CORP common stock, multiplied by the number of units credited to an Eligible Employee’s Account, shall be credited to the Eligible Employee’s Account and converted into additional units. The number of additional units shall be calculated by dividing the aggregate amount of credited dividends, i.e., the dividend multiplied by the number of units credited to the Eligible Employee’s Account as of the dividend record date, by the closing price of a share of PG&E CORP common stock on the New York Stock Exchange on the dividend payment date. If, after the record date but before the dividend payment date, an Eligible Employee’s balance in the PG&E CORP Phantom Stock Fund has been reallocated to another Investment Fund(s) or has been paid to the Eligible Employee or to the Eligible Employee’s beneficiary, other than pursuant to an election under Sections 7(c)(2) or 8, then an amount equal to the aggregated dividend shall be credited to the Eligible Employee’s Account in such other Investment Fund(s) or paid directly to the Eligible Employee or the Eligible Employee’s beneficiary, whichever is applicable.
(3)    S&P 500 Index Fund. Amounts credited to the S&P 500 Index Fund shall be converted into units each representing a Large Company Stock Fund (LCSF) unit held in the RSP on the date of allocation. Thereafter, the value of a unit held in the S&P Index Fund shall be determined in the same manner as the value of a LCSF unit under Section 18 of the RSP.
6.    Accounting.
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(a)    Eligible Employees’ Accounts. At the direction of the Plan Administrator, there shall be established and maintained on the books of the Employer, a separate account for each Eligible Employee in order to reflect his or her interest under the Plan.
(b)    Investment Earnings. Each Eligible Employee’s Account shall initially reflect the value of his or her Account’s interest in each of the Investment Funds, deemed acquired with the amounts credited thereto. Each Eligible Employee’s Account shall also be credited (or debited) as of the end of each day with the net appreciation (or depreciation), earnings and gains (or losses) with respect to the investments deemed made by his or her Account. Any such net earnings or gains deemed realized with respect to any investment of any Eligible Employee’s Account shall be deemed reinvested in additional amounts of the same investment and credited to the Eligible Employee’s Account.
(c)    Accounting Methods. The accounting methods or formulae to be used under the Plan for the purpose of maintaining the Eligible Employees’ Accounts shall be determined by the Plan Administrator. The accounting methods or formulae selected by the Plan Administrator may be revised from time to time but shall conform to the extent practicable with the accounting methods used under the Applicable Plan.
(d)    Valuations and Reports. The fair market value of each Eligible Employee’s Account shall be determined as of each Valuation Date. In making such determinations and in crediting net deemed earnings and gains (or losses) in the Investment Funds to the Eligible Employees’ Accounts, the Plan Administrator (in its discretion) may employ such accounting methods as the Plan Administrator (in its discretion) may deem appropriate in order to fairly reflect the fair market values of the Investment Funds and each Eligible Employee’s Account. For this purpose, the Plan Administrator may rely upon information provided by the Plan Administrator or other persons believed by the Plan Administrator to be competent.
(e)    Statements of Eligible Employee’s Accounts. Each Eligible Employee shall be furnished with periodic statements of his or her interest in the Plan, at least annually.
7.    Distributions.
(a)    Distribution of Account Balances. Unless the Eligible Employee has elected otherwise under this Section 7, distribution of the balance credited to an Eligible Employee’s Account shall be made in a single sum in the January of the year following Retirement or termination of service:
(1)    In the case of an Alternate Payee (as defined in Section 9(a)), distribution shall be made as directed in a domestic relations order which the Plan Administrator determines is a QDRO (as defined in Section 9(a)), but only as to the portion of the Eligible Employee’s Account which the QDRO states is payable to the Alternate Payee.
(2)    Any provisions of the Plan notwithstanding distribution of account balances must commence no later than in the January following the year which the Eligible Employee reaches age 72.
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(b)    Installment Distributions. In lieu of a single sum payment, an Eligible Employee whose Account value (exclusive of Special Incentive Stock Ownership Premiums) is at least $5,000 may elect in writing and file with the Plan Administrator an election that payment of amounts credited to the Eligible Employee’s Account be made in a specified number of approximately equal annual installments (not in excess of 10). However, if during the installment payment period the Account balance, exclusive of Special Incentive Stock Ownership Premiums, is less than $5,000, the value of the remaining installments shall be paid as a lump sum. All installment payments will be made during the month of January.
(c)    Early Distributions. By filing an irrevocable election with the Plan Administrator, an Eligible Employee may elect to commence distribution of full or partial payment at any time other than Retirement or termination, provided that:
(1)    such election is made at least one year prior to the Retirement or termination of the Eligible Employee and does not provide for the receipt of such amounts earlier than one year from the date of the election; or
(2)    the Eligible Employee elects to forfeit 10 percent of the value of the requested distribution, valued as of the new date for distribution of such Account funds, and such Eligible Employee shall not be permitted to make future deferrals for 24 months following such distribution.
All early distributions elected pursuant to Section 7(c)(1) must be made during the month of January.
(d)    Death Distributions. If an Eligible Employee dies before the entire balance of his or her Account has been distributed (whether or not the Eligible Employee had previously terminated employment and whether or not installment payments had previously commenced), the remaining balance of the Eligible Employee’s Account shall be distributed to the beneficiary designated or otherwise determined in accordance with Section 7(g), as soon as practicable after the date of death.
(e)    Special Incentive Stock Ownership Premiums. Distributions attributable to Special Incentive Stock Ownership Premiums shall only be made in January following the year in which an Eligible Employee terminates employment, Retires, or dies, and shall only be made in the form of one or more certificates for the number of vested Special Incentive Stock Ownership Premium units, rounded down to the nearest whole share.
(f)    Effect of Change in Eligible Employee Status. If an Eligible Employee ceases to be an Eligible Employee, the balance credited to his or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 7; provided, however, that if an Eligible Employee terminates employment with an Employer other than by reason of Retirement, the entire balance credited to his or her Account shall be distributed in a lump sum cash payment in January of the year following the year of termination of employment. Anything to the contrary notwithstanding, the Plan Administrator, in its sole discretion, may authorize an accelerated distribution of the balance credited to his or her Account in the form of a lump sum cash payment as of any earlier date.
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(g)    Payments to Incompetents. If any individual to whom a benefit is payable under the Plan is a minor or if the Plan Administrator determines that any individual to whom a benefit is payable under the Plan is incompetent to receive such payment or to give a valid release therefor, payment shall be made to the guardian, committee, or other representative of the estate of such individual which has been duly appointed by a court of competent jurisdiction. If no guardian, committee, or other representative has been appointed, payment may be made to any person as custodian for such individual under the California Uniform Transfers to Minors Act (or similar law of another state) or may be made to or applied to or for the benefit of the minor or incompetent, the incompetent’s spouse, children or other dependents, the institution or persons maintaining the minor or incompetent, or any of them, in such proportions as the Plan Administrator from time to time shall determine; and the release of the person or institution receiving the payment shall be a valid and complete discharge of any liability of PG&E CORP with respect to any benefit so paid.
(h)    Beneficiary Designations. Each Eligible Employee may designate, in a signed writing delivered to the Plan Administrator, on such form as it may prescribe, one or more beneficiaries to receive any distribution which may become payable under the Plan as the result of the Eligible Employee’s death. An Eligible Employee may designate different beneficiaries at any time by delivering a new designation in like manner. Any designation shall become effective only upon its receipt by the Plan Administrator, and the last effective designation received by the Plan Administrator shall supersede all prior designations. If an Eligible Employee dies without having designated a beneficiary or if no beneficiary survives the Eligible Employee, the Eligible Employee’s Account shall be payable to the beneficiary or beneficiaries designated or otherwise determined under the RSP.
(i)    Undistributable Accounts. Each Eligible Employee and (in the event of death) his or her beneficiary shall keep the Plan Administrator advised of his or her current address. If the Plan Administrator is unable to locate the Eligible Employee or beneficiary to whom an Eligible Employee’s Account is payable under this Section 7, the Eligible Employee’s Account shall be frozen as of the date on which distribution would have been completed in accordance with this Section 7, and no further appreciation, depreciation, earnings, gains or losses shall be credited (or debited) thereto. PG&E CORP shall have the right to assign or transfer the liability for payment of any undistributable Account to the Eligible Employee’s former Employer (or any successor thereto).
(j)    Plan Administrator Discretion. Within the specific time periods described in this Section 7, the Plan Administrator shall have sole discretion to determine the specific timing of the payment of any Account balance under the Plan.
8.    Distribution Due to Unforeseeable Emergency (Hardship Distribution)
A participant may request a distribution due to an unforeseeable emergency by submitting a written request to the Plan Administrator. The Plan Administrator shall have the authority to require such evidence as it deems necessary to determine if a distribution is warranted. If an application for a hardship distribution due to an unforeseeable emergency is approved, the distribution shall be payable in a method determined by the Plan Administrator as soon as possible after approval of such distribution. After receipt of a payment requested due to an unforeseeable emergency, a participant may not make additional deferrals during the remainder of the Plan Year in
    -9-

which the recipient received the payment. A participant who has commenced receiving installment payments under the Plan may request acceleration of such payments in the event of an unforeseeable emergency. The Administrator may permit accelerated payments to the extent such accelerated payment does not exceed the amount necessary to meet the emergency.
9.    Domestic Relations Orders
(a)    Qualified Domestic Relations Orders. The Plan Administrator shall establish written procedures for determining whether a domestic relations order purporting to dispose of any portion of an Eligible Employee’s Account is a qualified domestic relations order (within the meaning of Section 414(p) of the Code) (a “QDRO”).
(1)    No Payment Unless a QDRO. No payment shall be made to any person designated in a domestic relations order (an “Alternate Payee”) until the Plan Administrator (or a court of competent jurisdiction reversing an initial adverse determination by the Plan Administrator) determines that the order is a QDRO. Payment shall be made to each Alternate Payee as specified in the QDRO.
(2)    Time of Payment. Payment may be made to an Alternate Payee in the form of a lump sum, at the time specified in the QDRO, but no earlier than as soon as practicable following the date the QDRO determination is made.
(3)    Hold Procedures. Notwithstanding any contrary Plan provision, prior to the receipt of a domestic relations order, the Plan Administrator may, in its sole discretion, place a hold upon all or a portion of an Eligible Employee’s Account for a reasonable period of time (as determined by the Plan Administrator) if the Plan Administrator receives notice that (a) a domestic relations order is being sought by the Eligible Employee, his or her spouse, former spouse, child or other dependent, and (b) the Eligible Employee’s Account is a source of the payment under such domestic relations order. For purposes of this Section 9(a)(3), a “hold” means that no withdrawals, distributions, or investment transfers may be made with respect to an Eligible Employee’s Account. If the Plan Administrator places a hold upon an Eligible Employee’s Account pursuant to this Section 9(a)(3), it shall inform the Eligible Employee of such fact.
10.    Vesting
Except as provided in Section 4(d), an Eligible Employee’s interest in his or her Account at all times shall be 100 percent vested and nonforfeitable.
11.    Administration of the Plan
(a)    Plan Administrator. The Employee Benefit Committee of PG&E CORP is hereby designated as the administrator of the Plan (within the meaning of Section 3(16)(A) of ERISA). The Plan Administrator delegates to the Senior Human Resource Officer for PG&E CORP, or his or her designee, the authority to carry out all duties and responsibilities of the Plan Administrator under the Plan. The Plan Administrator shall have the authority to control and manage the operation and administration of the Plan.
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(b)    Powers of Plan Administrator. The Plan Administrator shall have all discretion and powers necessary to supervise the administration of the Plan and to control its operation in accordance with its terms, including, but not by way of limitation, the power to interpret the provisions of the Plan and to determine, in its sole discretion, any question arising under, or in connection with the administration or operation of, the Plan.
(c)    Decisions of Plan Administrator. All decisions of the Plan Administrator and any action taken by it in respect of the Plan and within the powers granted to it under the Plan shall be conclusive and binding on all persons and shall be given the maximum deference permitted by law.
12.    Funding
All amounts credited to an Eligible Employee’s Account under the Plan shall continue for all purposes to be a part of the general assets of PG&E CORP. The interest of the Eligible Employee in his or her Account, including his or her right to distribution thereof, shall be an unsecured claim against the general assets of PG&E CORP. While PG&E CORP may choose to invest a portion of its general assets in investments identical or similar to those selected by Eligible Employees for purposes of determining the amounts to be credited (or debited) to their Accounts, nothing contained in the Plan shall give any Eligible Employee or beneficiary any interest in or claim against any specific assets of PG&E CORP.
13.    Modification or Termination of Plan
(a)    Employers’ Obligations Limited. The Plan is voluntary on the part of the Employers, and the Employers do not guarantee to continue the Plan. PG&E CORP at any time may, by appropriate amendment of the Plan, suspend Matching Employer Contributions and/or Basic Employer Contributions or may discontinue Matching Employer Contributions and/or Basic Employer Contributions, with or without cause.
(b)    Right to Amend or Terminate. The Board of Directors, acting through its Nominating and Compensation Committee, reserves the right to alter, amend, or terminate the Plan, or any part thereof, in such manner as it may determine, for any reason whatsoever.
(1)    Limitations. Any alteration, amendment, or termination shall take effect upon the date indicated in the document embodying such alteration, amendment, or termination, provided that no such alteration or amendment shall divest any portion of an Account that is then vested under the Plan.
(c)    Effect of Termination. If the Plan is terminated, the balances credited to the Accounts of the Eligible Employees affected by such termination shall be distributed to them at the time and in the manner set forth in Section 7; provided, however, that the Plan Administrator, in its sole discretion, may authorize accelerated distribution of Eligible Employees’ Accounts as of any earlier date.
14.    General Provisions
(a)    Inalienability. Except to the extent otherwise directed by a domestic relations order which the Plan Administrator determines is a QDRO (as defined in Section
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9(a) or mandated by applicable law, in no event may either an Eligible Employee, a former Eligible Employee or his or her spouse, beneficiary or estate sell, transfer, anticipate, assign, hypothecate, or otherwise dispose of any right or interest under the Plan; and such rights and interests shall not at any time be subject to the claims of creditors nor be liable to attachment, execution, or other legal process.
(b)    Rights and Duties. Neither the Employers nor the Plan Administrator shall be subject to any liability or duty under the Plan except as expressly provided in the Plan, or for any action taken, omitted, or suffered in good faith.
(c)    No Enlargement of Employment Rights. Neither the establishment or maintenance of the Plan, the making of any Matching Employer Contributions, nor any action of any Employer or Plan Administrator, shall be held or construed to confer upon any individual any right to be continued as an Employee nor, upon dismissal, any right or interest in any specific assets of the Employers other than as provided in the Plan. Each Employer expressly reserves the right to discharge any Employee at any time, with or without cause or advance notice.
(d)    Apportionment of Costs and Duties. All acts required of the Employers under the Plan may be performed by PG&E CORP for itself and its Participating Subsidiaries, and the costs of the Plan may be equitably apportioned by the Plan Administrator among PG&E CORP and the other Employers. Whenever an Employer is permitted or required under the terms of the Plan to do or perform any act, matter or thing, it shall be done and performed by any officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer.
(e)    Applicable Law. The provisions of the Plan shall be construed, administered, and enforced in accordance with the laws of the State of California and, to the extent applicable, ERISA.
(f)    Severability. If any provision of the Plan is held invalid or unenforceable, its invalidity or unenforceability shall not affect any other provisions of the Plan, and the Plan shall be construed and enforced as if such provision had not been included.
(g)    Captions. The captions contained in and the table of contents prefixed to the Plan are inserted only as a matter of convenience and for reference and in no way define, limit, enlarge, or describe the scope or intent of the Plan nor in any way shall affect the construction of any provision of the Plan.
15.    Claims and Appeals Procedure
Any claims for benefits under the Plan made by a participant, beneficiary or other person shall be made and administered in accordance with the following procedures.
(a)    Compliance with Regulations. It is intended that the claims procedure of the Plan be administered in accordance with the claims procedure regulations of the U.S. Department of Labor set forth in 29 C.F.R. Section 2560.503-1.
(b)    Initial Claims.
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(1)    Submission of Initial Claims by a Claimant. Claims for benefits under the Plan made by a participant, beneficiary or other person covered or claiming they are entitled to benefits from the Plan (a “Claimant”) (or by an authorized representative of any Claimant) must be submitted in writing to the Director, Benefits, or if the title for the position ever changes, the individual employed in Benefits with direct management responsibility over the Plan (whether a Manager or some other title) (such individual, the “Initial Claim Reviewer”), care of Benefits.
(2)    Authorized Representative. The Plan Administrator may establish and enforce reasonable procedures for determining whether any individual or entity has been authorized to act on behalf of a Claimant.
(3)    Processing of Approved Claims. Approved claims will be processed and, if applicable, the Plan Administrator will issue instructions authorizing payments as approved.
(4)    Notification of Denied Claims. If a claim is denied in whole or in part by the Initial Claim Reviewer in its discretion, the Initial Claim Reviewer shall notify the Claimant of the decision by written or electronic notice, in a manner calculated to be understood by the Claimant. The notice shall set forth:
a)    The specific reasons for the denial of the claim;
b)    A reference to specific provisions of the Plan on which the denial is based;
c)    A description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
d)    An explanation of the Plan’s claims review procedure for the denied or partially denied claim and any applicable time limits, and a statement that the Claimant has a right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review.
Such notification shall be given within 90 days after the claim is received by the Initial Claim Reviewer (or within 180 days, if special circumstances require an extension of time for processing the claim and provided that written notice of such extension and circumstances and the date a decision is expected is given to the Claimant within the initial 90-day period). A claim is considered approved only if its approval is communicated in writing to a Claimant.
(c)    Appeals of Denied Claims.
(1)    Right to Appeal. Upon denial of a claim in whole or in part, a Claimant or his or her duly authorized representative shall have the right to submit a written request to the Employee Benefit Appeals Committee, as such term is defined the Pacific Gas and Electric Company Retirement Plan Part I, as amended and restated from time to time (the “Employee Benefit Appeals Committee”) for a full and fair review of the denied claim. A request for review of a claim must be submitted within 60 days of receipt by the
    -13-

Claimant of written notice of the denial of the claim. If the Claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the Claimant is precluded from reasserting it. Also, if the Claimant is not provided a notice of denial of an initial claim as set forth in Section 15(b), the Claimant may submit a written request for review to the Employee Benefit Appeals Committee.
(2)    Access to Documents and Records. The Claimant or the Claimant’s representative shall have, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits.
(3)    Right to Submit Additional Information. The Claimant may submit written comments, documents, records and other information relating to the claim for benefits.
(4)    Scope of the Review. The Employee Benefit Appeals Committee review process shall include all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
(5)    Preclusion for Materials Not Submitted. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(6)    Decision by the Employee Benefit Appeals Committee. The decision by the Employee Benefit Appeals Committee on review shall be in written or electronic form, in a manner calculated to be understood by the Claimant. If the claim is denied on review, the notice shall set forth:
a)    The specific reasons for the denial of the appeal of the claim;
b)    A reference to specific provisions of the Plan on which the denial is based;
c)    A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and;
d)    A statement describing any voluntary appeal procedures offered by the Plan (if any) and the Claimant’s right to obtain the information about such procedures, and a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA.
The Employee Benefit Appeals Committee will advise the Claimant of the results of the review within 60 days after receipt of the written request for review (or within 120 days if special circumstances require an extension of time for processing the request, and if notice of such extension and circumstances, including the date a decision is expected to be made, is given to such Claimant within the initial 60-day period).
    -14-

(d)    Authority of Initial Claim Reviewer and Employee Benefit Appeals Committee and Deference to their Decisions. To the extent of the responsibility to review initial benefit claims (with respect to the Initial Claim Reviewer) or to review appeals of the denial of benefit claims (with respect to the Employee Benefit Appeals Committee), the Initial Claim Reviewer and the Employee Benefit Appeals Committee, shall have the discretionary authority to interpret and apply the provisions of the Plan and such decisions shall be afforded the maximum deference permitted by law. Benefits will be paid only if the Initial Claim Reviewer (with respect to initial benefit claims) or the Employee Benefit Appeals Committee (with respect to appeals of the denial of benefit claims) decides in its discretion that the Claimant is entitled to them. The decisions of the Employee Benefit Appeals Committee shall be final and binding on the Claimant.
(e)    Exhaustion of Claims Procedure Required in All Cases. A participant, beneficiary or other person asserting a claim, alleging a violation of or seeking any remedy under any provision of ERISA or other applicable law that relates in any manner to the Plan is considered a Claimant and is subject to the claims procedures described in this Section 15.
A participant, beneficiary or other person made subject to the claims procedures in this Section 15 must follow and exhaust the applicable claims procedures described in this Section 15 with respect to any claim, alleged violation, or sought remedy before taking action in any other forum regarding a claim for benefits under the Plan or alleging a violation of, or seeking any remedy under, any provision of ERISA or other applicable law.
A Claimant and any representative of a Claimant may not bring an action in any other forum later than the earliest of (1) one year from the date of completion of the Plan’s claims appeal process set forth in this Section 15, (2) one year from the latest date on which an appeal is permitted to be filed under this claims and appeals process after the denial of an initial claim (i.e., within 60 days of receipt of an initial claim denial notification), and (3) two years from the date a Claimant knew or should have known that a claim existed. The foregoing in no way serves as a waiver of the exhaustion requirement set forth in the preceding paragraph.
Any action described in this Section 15(e) must be filed in the Federal District Court for the Northern District of California.


    -15-

APPENDIX A
PARTICIPATING SUBSIDIARIES
Participating Subsidiaries as of January 1, 1997
– PG&E Gas Transmission Corporation
– PG&E Gas Transmission, Texas Corporation
– PG&E Gas Transmission TECO, Inc.
– PG&E Energy Trading-Gas Corporation
– PG&E Energy Services Corporation
– And the U.S. subsidiaries of each of the above-named corporations.
Additional Participating Subsidiaries as of January 1, 1998
– PG&E Corporation
– Pacific Gas and Electric Company
– PG&E Generating Company
– PG&E Corporation Support Services, Inc.
– And the U.S. subsidiaries of each of the above-named corporations.

    -16-




PG&E CORPORATION
SUPPLEMENTAL RETIREMENT SAVINGS PLAN

    -17-
TABLE OF CONTENTS

Page
1.    Purpose of the Plan    1
2.    Definitions    1
3.    Employer Contributions    3
4.    Eligible Employee Deferrals    5
5.    Investment Funds    6
6.    Accounting    7
7.    Distributions    8
8.    Distribution Due to Unforeseeable Emergency (Hardship Distribution)    11
9.    Domestic Relations Orders    11
10.    Vesting    12
11.    Administration of the Plan    12
12.    Funding    12
13.    Modification or Termination of Plan    12
14.    General Provisions    13
15.    Claims and Appeals Procedure    14
Appendix A    18
End of TOC - Do not delete this paragraph!
-i-

EXHIBIT 10.3

PG&E CORPORATION
2005 SUPPLEMENTAL RETIREMENT SAVINGS PLAN

This is the controlling and definitive statement of the PG&E CORPORATION (“PG&E CORP”) 2005 Supplemental Retirement Savings Plan (the “Plan”). The Plan was amended for compliance with the final Code Section 409A regulations effective as of January 1, 2009, further amended effective July 13, 2009 and August 1, 2011 with respect to available investment options, further amended effective September 17, 2013 with respect to default investment funds and election of installment payments, further amended effective September 15, 2015 with respect to salary deferral percentages and crediting of matching contributions upon Separation from Service, further amended effective January 1, 2022 to reflect changes to officer characterization, further amended effective February 15, 2023 with respect to when contribution payments are made under the Plan, and further amended effective September 12, 2023 to add claims and appeals procedures. Except as provided herein, the Plan is generally effective as of January 1, 2005, with respect to all individuals who are Eligible Employees as of such date. The Plan continues the benefit program embodied in the PG&E Corporation Supplemental Retirement Savings Plan (the “Prior Plan”). Benefits accrued under the Prior Plan continue to be payable under the Prior Plan pursuant to the terms and conditions of the Prior Plan.
1.    Purpose of the Plan. The Plan is established and is maintained for the benefit of a select group of management and highly compensated employees of PG&E CORP and its Participating Subsidiaries in order to provide such employees with certain deferred compensation benefits. The Plan is an unfunded deferred compensation plan that is intended to qualify for the exemptions provided in Sections 201, 301, and 401 of ERISA.
2.    Definitions. The following words and phrases shall have the following meanings unless a different meaning is plainly required by the context:
(a)    “Basic Employer Contributions” shall mean the amounts credited to Eligible Employees’ Accounts under the Plan by the Employers, in accordance with Section 3(c).
(b)    “Board of Directors” shall mean the Board of Directors of PG&E CORP, as from time to time constituted.
(c)    “Code” shall mean the Internal Revenue Code of 1986, as amended. Reference to a specific section of the Code shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.
(d)    “Committee” shall mean the Compensation Committee of the Board, as it may be constituted from time to time.
(e)    “Eligible Employee” shall mean an Employee who:
(1)    Is an officer of PG&E CORP or any Participating Subsidiary with the title of Vice President, Senior Vice President, Executive Vice President, or higher; or
(2)    Is a key employee of PG&E CORP or any Participating Subsidiary and who is designated by the Plan Administrator as eligible to participate in the Plan.
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(f)    “Eligible Employee’s Account” or “Account” shall mean as to any Eligible Employee, the separate account maintained on the books of the Employer in accordance with Section 6(a) in order to reflect his or her interest under the Plan. Accounts shall be centrally administered by the Plan Administrator or its designee.
(g)    “Employee” shall mean an individual who is treated in the records of an Employer as an employee of the Employer, who is not on an unpaid leave of absence, and/or who is not covered by a collective bargaining agreement; provided, however, such term shall not mean an individual who is a “leased employee” or who has entered into a written contract or agreement with an Employer which explicitly excludes such individual from participation in an Employer’s benefit plans. The provisions of this definition shall govern, whether or not it is determined that an individual otherwise meets the definition of “common law” employee.
(h)    “Employers” shall mean PG&E CORP and the Participating Subsidiaries designated by the Employee Benefit Committee of PG&E CORP. An initial list of the Employers is contained in Appendix A to this Plan.
(i)    “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. Reference to a specific section of ERISA shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.
(j)    “Investment Funds” shall mean the investment funds established by the Board of Directors and reflected from time to time on Appendix B. The Investment Funds shall be used for tracking phantom investment results under the Plan.
(k)    “Matching Employer Contributions” shall mean the amounts credited to Eligible Employees’ Accounts under the Plan by the Employers, in accordance with Section 3(b).
(l)    “Participating Subsidiary” shall mean a United States-based subsidiary of PG&E CORP, which has been designated by the Employee Benefit Committee of PG&E CORP as a Participating Subsidiary under this Plan and which has agreed to make payments or reimbursements with respect to its Eligible Employees pursuant to Section 14(d). At such times and under such conditions as the Employee Benefit Committee may direct, one or more other subsidiaries of PG&E CORP may become Participating Subsidiaries or a Participating Subsidiary may be withdrawn from the Plan. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan.
(m)    “PG&E CORP” shall mean PG&E Corporation, a California corporation.
(n)    “Plan” shall mean the PG&E Corporation 2005 Supplemental Retirement Savings Plan, as set forth in this instrument and as heretofore and hereafter amended from time to time.
(o)    “Plan Year” shall mean the calendar year.
(p)    “Prior Plan” shall mean the PG&E Corporation Supplemental Retirement Savings Plan.
(q)    “Retirement” or “Retire” shall mean an Eligible Employee’s Separation from Service, provided that the Eligible Employee is at least 55 years of age and has been employed by an Employer for at least five consecutive years prior to the Separation from Service.
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(r)    “RSP” shall mean, with respect to any Eligible Employee, the PG&E Corporation Retirement Savings Plan or any predecessor qualified retirement plan sponsored by PG&E CORP or any of its subsidiary companies.
(s)    “Separation from Service” shall mean an Eligible Employee’s “separation from service” within the meaning of Code Section 409A(a)(2)(A)(i) and related Treasury Regulations and other guidance, as determined by the Plan Administrator in its discretion.
(t)    “Valuation Date” shall mean:
(1)    For purposes of valuing Plan assets and Eligible Employees’ Accounts for periodic reports and statements, the date as of which such reports or statements are made; and
(2)    For purposes of determining the amount of assets actually distributed to the Eligible Employee, his or her beneficiary, or an Alternate Payee (or available for withdrawal), a date that shall not be more than seven business days prior to the date the check is issued to the Eligible Employee.
In any other case, the Valuation Date shall be the date designated by the Plan Administrator (in its discretion) or the date otherwise set forth in this Plan. In all cases, the Plan Administrator (in its discretion) may change the Valuation Date, on a uniform and nondiscriminatory basis, as is necessary or appropriate. Notwithstanding the foregoing, the Valuation Date shall occur at least annually.
3.    Employer Contributions.
(a)    Matching Employer Contributions. Subject to the provisions of Section 13, the Eligible Employee’s Account shall be credited for each Plan Year with a Matching Employer Contribution, calculated in the manner provided in Sections 3(a)(1), (2), and (3) below:
(1)    First, an amount shall be calculated equal to the maximum matching contribution that would be made under the terms of the RSP, taking into account for such Plan Year the amount of pre-tax deferrals and after-tax contributions the Eligible Employee elected under the RSP. For purposes of this calculation, any amounts deferred under Subsection 4(a) of this Plan shall be treated as pre-tax deferrals under the RSP.
(2)    The calculation made in accordance with this Section 3(a)(1) above shall be made without regard to any limitation on such amounts under the RSP resulting from the application of any of the limitations under Code Sections 401(m), 401(a)(17), or 415.
(3)    The Employer Matching Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(a)(1) and (2) above, reduced by the amount of matching contribution made to such Eligible Employee’s account for such Plan Year under the RSP.
(b)    Crediting of Matching Employer Contributions. Matching Employer Contributions shall be calculated and credited to the Eligible Employee’s Account as of the first business day of February of the calendar year following the Plan Year and shall be credited only if the Eligible Employee was an Eligible Employee on at least one day of the Plan Year for which the amounts are credited, except that if an Eligible Employee Separates from Service on or after September 15, 2015, then upon that Eligible Employee’s Separation from Service, the value of the Matching Employer Contribution for the Plan Year during which Separation from Service occurs shall instead be calculated and credited to the Eligible Employee’s Account as soon as
3


practicable, as determined by PG&E CORP. All such amounts shall be deemed to be invested in an Investment Fund designated by the Plan Administrator.
(c)    Basic Employer Contributions. Subject to the provisions of Section 13, the Account of each Eligible Employee shall be credited for each Plan Year with a Basic Employer Contribution, calculated in the manner provided in Sections 3(c)(1), (2), and (3) below:
(1)    First, an amount shall be calculated equal to the Basic Employer Contribution that would be made under the terms of the RSP, taking into account for such Plan Year the Eligible Employee’s Covered Compensation under the RSP, before any deductions for compensation deferrals elected by such Eligible Employee under Subsection 4(a) of this Plan. For Eligible Employees as defined by Section 2(e)(1) of this Plan, compensation shall also reflect such Eligible Employee’s Short-Term Incentive Plan awards.
(2)    The calculation made in accordance with this Section 3(c)(1) above shall be made without regard to any limitation on such amounts under the RSP resulting from the application of any of the limitations under Code Sections 401(a)(4), 401(a)(17), or 415.
(3)    The Employer Contribution to be credited to the Account of an Eligible Employee for any Plan Year shall equal the amount calculated in accordance with Sections 3(c)(1) and (2) above, reduced by the amount of Basic Employer Contributions made to such Eligible Employee’s account for such Plan Year under the RSP.
(d)    Crediting of Basic Employer Contributions. The Employer Contribution attributable to an Eligible Employee’s Short Term Incentive Plan award shall be credited to an Eligible Employee’s Account as of the first business day of the month following the date on which the Short-Term Incentive Plan award is paid. All other Employer Contributions made in respect of an Eligible Employee shall be credited to the Eligible Employee’s Account as of the first business day of February of the calendar year following the Plan Year and shall be credited only if the Eligible Employee is an Employee on the last day of the Plan Year for which the amounts are credited. All such amounts shall be deemed to be invested in an Investment Fund designated by the Plan Administrator.
(e)    FICA Taxes. Each Eligible Employee shall be responsible for FICA taxes on amounts credited to his or her Account under Sections 3 and 4(d).
4.    Eligible Employee Deferrals.
(a)    Amount of Deferral. An Eligible Employee may defer all or part of his or her annual salary, Short Term Incentive Plan awards, Long-Term Incentive Plan (LTIP) awards (other than stock options), Perquisite Allowances, and any other special payments, awards, or bonuses as authorized by the Plan Administrator.
(b)    Credits to Accounts. Salary deferrals shall be credited to an Eligible Employee’s Account as of each payroll period. All other deferrals attributable to allowances, awards, bonuses, and other payments shall be credited as soon as practicable, but no more than 30 days after the date that they otherwise would have been paid.
(c)    Deferral Election. An Eligible Employee must file an election form with the Plan Administrator which indicates the percentage of salary and the amount of any awards, allowances, payments, and bonuses to be deferred under the Plan. The election shall occur no later than December 31 (or such earlier date established by the Plan Administrator) of the calendar year next preceding the service year (within the meaning of Treasury Regulation Section 1.409A-2(a)(3)). Notwithstanding the foregoing, to the extent permitted under Treasury
4


Regulation Section 1.409A-2(a)(7), upon first becoming an Eligible Employee, an election to defer shall be effective for compensation to be earned for services performed beginning in the month following the filing of a Deferral Election Form, provided said Form is filed within 30 days following the date when the employee first becomes an Eligible Employee. Notwithstanding the foregoing, in the case of performance-based compensation (within the meaning of Treasury Regulation Section 1.409A-1(e)), the election may be made with respect to such performance-based compensation on or before the date that is six months before the end of the applicable performance period to the extent permitted under Treasury Regulation Section 1.409A-2(a)(8). The Plan Administrator may, in its sole discretion, permit elections to be made under other timing rules that comply with Code Section 409A.
(d)    Deferral of Special Incentive Stock Ownership Premiums. All of an Eligible Employee’s Special Incentive Stock Ownership Premiums are automatically deferred to the Plan immediately upon grant and converted into units in the PG&E Corporation Phantom Stock Fund. The units attributable to Special Incentive Stock Ownership Premiums and any additional units resulting from the conversion of dividend equivalents thereon remain unvested until the earlier of the third anniversary of the date on which the Special Incentive Stock Ownership Premiums are credited to an Eligible Employee’s account (provided the Eligible Employee continues to be employed on such date), death, disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code), or Retirement of the participant, or upon a Change in Control (as defined in the LTIP). Unvested units attributable to Special Incentive Stock Ownership Premiums and any additional units resulting from the conversion of dividend equivalents thereon shall be forfeited upon termination of the Eligible Employee’s employment (unless otherwise provided in the PG&E Corporation Executive Stock Ownership Program or the PG&E Corporation Officer Severance Plan) or if an Eligible Employee’s stock ownership falls below the levels set forth in the Executive Stock Ownership Program.
5.    Investment Funds. Although no assets will be segregated or otherwise set aside with respect to an Eligible Employee’s Account, the amount that is ultimately payable to the Eligible Employee with respect to such Account shall be determined as if such Account had been invested in some or all of the Investment Funds. The Plan Administrator, in its sole discretion, shall adopt (and modify from time to time) such rules and procedures as it deems necessary or appropriate to implement the deemed investment of the Eligible Employees’ Accounts. Such procedures generally shall provide that an Eligible Employee’s Account shall be deemed to be invested among the available Investment Funds in the manner elected by the Eligible Employee in such percentages and manner as prescribed by the Plan Administrator. In the event no election has been made by the Eligible Employee, such Account will be deemed to be invested in an Investment Fund designated by the Plan Administrator. Eligible Employees shall be able to reallocate their Accounts between the Investment Funds and reallocate amounts newly credited to their Accounts at such time and in such manner as the Plan Administrator shall prescribe. Anything to the contrary herein notwithstanding, an Eligible Employee may not reallocate Account balances between Investment Funds if such reallocation would result in a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any successor to Rule 16b-3, as in effect when the reallocation is requested. The available Investment Funds shall be listed on Appendix B and may be changed from time to time by the Board of Directors.
6.    Accounting.
(a)    Eligible Employees’ Accounts. At the direction of the Plan Administrator, there shall be established and maintained on the books of the Employer, a separate account for each Eligible Employee in order to reflect his or her interest under the Plan.
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(b)    Investment Earnings. Each Eligible Employee’s Account shall initially reflect the value of his or her Account’s interest in each of the Investment Funds, deemed acquired with the amounts credited thereto. Each Eligible Employee’s Account shall also be credited (or debited) with the net appreciation (or depreciation), earnings and gains (or losses) with respect to the investments deemed made by his or her Account. Any such net earnings or gains deemed realized with respect to any investment of any Eligible Employee’s Account shall be deemed reinvested in additional amounts of the same investment and credited to the Eligible Employee’s Account.
(c)    Accounting Methods. The accounting methods or formulae to be used under the Plan for the purpose of maintaining the Eligible Employees’ Accounts shall be determined by the Plan Administrator. The accounting methods or formulae selected by the Plan Administrator may be revised from time to time but shall conform to the extent practicable with the accounting methods used under the Applicable Plan.
(d)    Valuations and Reports. The fair market value of each Eligible Employee’s Account shall be determined as of each Valuation Date. In making such determinations and in crediting net deemed earnings and gains (or losses) in the Investment Funds to the Eligible Employees’ Accounts, the Plan Administrator (in its discretion) may employ such accounting methods as the Plan Administrator (in its discretion) may deem appropriate in order to fairly reflect the fair market values of the Investment Funds and each Eligible Employee’s Account. For this purpose, the Plan Administrator may rely upon information provided by the Plan Administrator or other persons believed by the Plan Administrator to be competent.
(e)    Statements of Eligible Employee’s Accounts. Each Eligible Employee shall be furnished with periodic statements of his or her interest in the Plan.
7.    Distributions.
(a)    Distribution of Account Balances. Except to the extent the Eligible Employee has elected otherwise under this Section 7 at the time of deferral, distribution of the balance credited to an Eligible Employee’s Account shall be made in a single lump sum as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service.
    In the case of an Alternate Payee (as defined in Section 9(a), to the extent allowable under Code Section 409A, distribution shall be made as directed in a domestic relations order which the Plan Administrator determines is a DRO (as defined in Section 9(a), but only as to the portion of the Eligible Employee’s Account which the DRO states is payable to the Alternate Payee.
(b)    Specific Distributions. In lieu of a payment described in Section 7(a), by filing an irrevocable election with the Plan Administrator, an Eligible Employee may at the time of deferral elect to receive distribution of the specific type of income deferral for that calendar year plus the earnings thereon (exclusive of Special Incentive Stock Ownership Premiums) in, or in the case of installments commencing in, January of any future year and in the form of either (1) a single lump sum or (2) from two to ten annual installments with subsequent installments paid on each anniversary of the installment commencement date.
(c)    Election of Installment Payments. In lieu of a single sum payment under Section 7(a), except in the case of Special Incentive Stock Ownership Premiums, an Eligible Employee may elect in writing to the Plan Administrator, on such form or in such other manner as it may prescribe, and file with the Plan Administrator an election that payment of amounts credited to the Eligible Employee’s Account be made in from 2 to 10 equal annual installments. If the
6


Eligible Employee elects installment payments pursuant to this Section 7(c), then such installment payments shall commence as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service (“Benefit Commencement Date”) and subsequent installments will be paid on each anniversary of the Benefit Commencement Date thereof until all installments are paid.
(d)    Change in Distribution Election. An Eligible Employee may change a distribution election previously made pursuant to Section 7(b) or 7(c) (or in place by default pursuant to Section 7(a)) only with respect to the portion of the Eligible Employee’s Account attributable to Eligible Employee Deferrals (exclusive of Special Incentive Stock Ownership Premiums) and only in accordance with the rules under Code Section 409A. Generally, a subsequent election pursuant to this Section 7(d): (1) cannot take effect for twelve (12) months, (2) must occur at least twelve (12) months before the first scheduled payment under a payment at a specified date elected pursuant to Section 7(b), and (3) must defer a previously elected distribution at least five (5) additional years. The Plan Administrator may establish additional rules or restrictions on changes in distribution elections.
(e)    Death Distributions. If an Eligible Employee dies before the balance of his or her Account has been distributed (whether or not the Eligible Employee had previously had a Separation from Service), the Eligible Employee’s Account shall be distributed in a lump sum to the beneficiary designated or otherwise determined in accordance with Section 7, as soon as practicable after the date of death (but in any event within 90 days after the date of death).
(f)    Special Incentive Stock Ownership Premiums. Distributions attributable to Special Incentive Stock Ownership Premiums shall only be made in the form of one or more certificates for the number of vested Special Incentive Stock Ownership Premium units, rounded down to the nearest whole share, in accordance with the timing rule set forth in Section 7(a).
(g)    Effect of Change in Eligible Employee Status. If an Eligible Employee ceases to be an Eligible Employee but does not experience a Separation from Service, the balance credited to his or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 7.
(h)    Payments to Incompetents. If any individual to whom a benefit is payable under the Plan is a minor or if the Plan Administrator determines that any individual to whom a benefit is payable under the Plan is incompetent to receive such payment or to give a valid release therefor, payment shall be made to the guardian, committee, or other representative of the estate of such individual which has been duly appointed by a court of competent jurisdiction. If no guardian, committee, or other representative has been appointed, payment may be made to any person as custodian for such individual under the California Uniform Transfers to Minors Act (or similar law of another state) or may be made to or applied to or for the benefit of the minor or incompetent, the incompetent’s spouse, children or other dependents, the institution or persons maintaining the minor or incompetent, or any of them, in such proportions as the Plan Administrator from time to time shall determine; and the release of the person or institution receiving the payment shall be a valid and complete discharge of any liability of PG&E CORP with respect to any benefit so paid.
(i)    Beneficiary Designations. Each Eligible Employee may designate, in a signed writing delivered to the Plan Administrator, on such form as it may prescribe, one or more beneficiaries to receive any distribution which may become payable under the Plan as the result of the Eligible Employee’s death. An Eligible Employee may designate different beneficiaries at any time by delivering a new designation in like manner. Any designation shall become effective only upon its receipt by the Plan Administrator, and the last effective designation
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received by the Plan Administrator shall supersede all prior designations. If an Eligible Employee dies without having designated a beneficiary or if no beneficiary survives the Eligible Employee, the Eligible Employee’s Account shall be payable to the beneficiary or beneficiaries designated or otherwise determined under the RSP.
(j)    Undistributable Accounts. Each Eligible Employee and (in the event of death) his or her beneficiary shall keep the Plan Administrator advised of his or her current address. If the Plan Administrator is unable to locate the Eligible Employee or beneficiary to whom an Eligible Employee’s Account is payable under this Section 7, the Eligible Employee’s Account shall be frozen as of the date on which distribution would have been completed in accordance with this Section 7, and no further appreciation, depreciation, earnings, gains or losses shall be credited (or debited) thereto. PG&E CORP shall have the right to assign or transfer the liability for payment of any undistributable Account to the Eligible Employee’s former Employer (or any successor thereto).
    (k)    Plan Administrator Discretion. Within the specific time periods described in this Section 7, the Plan Administrator shall have sole discretion to determine the specific timing of the payment of any Account balance under the Plan.
8.    Distribution Due to Unforeseeable Emergency (Hardship Distribution). A participant may request a distribution due to an unforeseeable emergency (within the meaning of Code Section 409A) by submitting a written request to the Plan Administrator. The Plan Administrator shall have the authority to require such evidence as it deems necessary to determine if a distribution is warranted. If an application for a hardship distribution due to an unforeseeable emergency is approved, the distribution shall be payable in a lump sum within 30 days after approval of such distribution. After receipt of a payment requested due to an unforeseeable emergency, a participant may not make additional deferrals during the remainder of the Plan Year in which the recipient received the payment. The distribution due to an unforeseeable emergency shall not exceed the amount reasonably necessary to meet the emergency. This Section 8 shall be administered in accordance with the requirements of Code Section 409A.
9.    Domestic Relations Orders.
(a)    Domestic Relations Orders. The Plan Administrator shall establish written procedures for determining whether an order purporting to dispose of any portion of an Eligible Employee’s Account is a domestic relations order (within the meaning of Section 414(p) of the Code) (a “DRO”).
(1)    No Payment Unless a DRO. No payment shall be made to any person designated in an order (an “Alternate Payee”) until the Plan Administrator (or a court of competent jurisdiction reversing an initial adverse determination by the Plan Administrator) determines that the order is a DRO. Payment shall be made to each Alternate Payee as specified in the DRO.
(2)    Time of Payment. Payment may be made to an Alternate Payee in the form of a lump sum, at the time specified in the DRO, but no earlier than the date the DRO determination is made.
(3)    Hold Procedures. Notwithstanding any contrary Plan provision, prior to the receipt of a domestic relations order, the Plan Administrator may, in its sole discretion, place a hold upon all or a portion of an Eligible Employee’s Account for a reasonable period of time (as determined by the Plan Administrator in accordance with Code Section 409A) if the Plan Administrator receives notice that (a) a domestic relations order is being sought by the Eligible
8


Employee, his or her spouse, former spouse, child or other dependent, and (b) the Eligible Employee’s Account is a source of the payment under such domestic relations order. For purposes of this Section 9(a)(3), a “hold” means that no withdrawals, distributions, or investment transfers may be made with respect to an Eligible Employee’s Account. If the Plan Administrator places a hold upon an Eligible Employee’s Account pursuant to this Section 9(a)(3), it shall inform the Eligible Employee of such fact.
10.    Vesting. Except as provided in Section 4(d), an Eligible Employee’s interest in his or her Account at all times shall be 100 percent vested and nonforfeitable.
11.    Administration of the Plan.
(a)    Plan Administrator. The Employee Benefit Committee of PG&E CORP is hereby designated as the administrator of the Plan (within the meaning of Section 3(16)(A) of ERISA). The Plan Administrator delegates to the Senior Human Resource Officer for PG&E CORP, or his or her designee, the authority to carry out all duties and responsibilities of the Plan Administrator under the Plan. The Plan Administrator shall have the authority to control and manage the operation and administration of the Plan.
(b)    Powers of Plan Administrator. The Plan Administrator shall have all discretion and powers necessary to supervise the administration of the Plan and to control its operation in accordance with its terms, including, but not by way of limitation, the power to interpret the provisions of the Plan and to determine, in its sole discretion, any question arising under, or in connection with the administration or operation of, the Plan.
(c)    Decisions of Plan Administrator. All decisions of the Plan Administrator and any action taken by it in respect of the Plan and within the powers granted to it under the Plan shall be conclusive and binding on all persons and shall be given the maximum deference permitted by law.
12.    Funding. All amounts credited to an Eligible Employee’s Account under the Plan shall continue for all purposes to be a part of the general assets of PG&E CORP. The interest of the Eligible Employee in his or her Account, including his or her right to distribution thereof, shall be an unsecured claim against the general assets of PG&E CORP. While PG&E CORP may choose to invest a portion of its general assets in investments identical or similar to those selected by Eligible Employees for purposes of determining the amounts to be credited (or debited) to their Accounts, nothing contained in the Plan shall give any Eligible Employee or beneficiary any interest in or claim against any specific assets of PG&E CORP.
13.    Modification or Termination of Plan.
(a)    Employers’ Obligations Limited. The Plan is voluntary on the part of the Employers, and the Employers do not guarantee to continue the Plan. PG&E CORP at any time may, by appropriate amendment of the Plan, suspend Matching Employer Contributions and/or Basic Employer Contributions or may discontinue Matching Employer Contributions and/or Basic Employer Contributions, with or without cause.
(b)    Right to Amend or Terminate. The Board of Directors, acting through the Committee, reserves the right to alter, amend, or terminate the Plan, or any part thereof, in such manner as it may determine, for any reason whatsoever.
(1)    Limitations. Any alteration, amendment, or termination shall take effect upon the date indicated in the document embodying such alteration, amendment, or termination,
9


provided that no such alteration or amendment shall divest any portion of an Account that is then vested under the Plan.
(c)    Effect of Termination. If the Plan is terminated, the balances credited to the Accounts of the Eligible Employees affected by such termination shall be distributed to them at the time and in the manner set forth in Section 7; provided, however, that the Plan Administrator, in its sole discretion, may authorize accelerated distribution of Eligible Employees’ Accounts to the extent provided in Treasury Regulation Sections 1-409A-3(j)(4)(ix) (A) (relating to terminations in connection with certain corporate dissolutions), (B) (relating to terminations in connection with certain change of control events), and (C) (relating to general terminations).
14.    General Provisions.
(a)    Inalienability. Except to the extent otherwise directed by a domestic relations order which the Plan Administrator determines is a DRO (as defined in Section 9(a)) or mandated by applicable law, in no event may either an Eligible Employee, a former Eligible Employee or his or her spouse, beneficiary or estate sell, transfer, anticipate, assign, hypothecate, or otherwise dispose of any right or interest under the Plan; and such rights and interests shall not at any time be subject to the claims of creditors nor be liable to attachment, execution, or other legal process.
(b)    Rights and Duties. Neither the Employers nor the Plan Administrator shall be subject to any liability or duty under the Plan except as expressly provided in the Plan, or for any action taken, omitted, or suffered in good faith.
(c)    No Enlargement of Employment Rights. Neither the establishment or maintenance of the Plan, the making of any Matching Employer Contributions, nor any action of any Employer or Plan Administrator, shall be held or construed to confer upon any individual any right to be continued as an Employee nor, upon dismissal, any right or interest in any specific assets of the Employers other than as provided in the Plan. Each Employer expressly reserves the right to discharge any Employee at any time, with or without cause or advance notice.
(d)    Apportionment of Costs and Duties. All acts required of the Employers under the Plan may be performed by PG&E CORP for itself and its Participating Subsidiaries, and the costs of the Plan may be equitably apportioned by the Plan Administrator among PG&E CORP and the other Employers. Whenever an Employer is permitted or required under the terms of the Plan to do or perform any act, matter or thing, it shall be done and performed by any officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. Each Participating Subsidiary shall be responsible for making benefit payments pursuant to the Plan on behalf of its Eligible Employees or for reimbursing PG&E CORP for the cost of such payments, as determined by PG&E CORP in its sole discretion. In the event the respective Participating Subsidiary fails to make such payment or reimbursement, and PG&E CORP does not exercise its discretion to make the payment on such Participating Subsidiary’s behalf, participation in the Plan by the Eligible Employees of that Participating Subsidiary shall be suspended in a manner consistent with Code Section 409A. If at some future date, the Participating Subsidiary makes all past-due payments and reimbursements, plus interest at a rate determined by PG&E CORP in its sole discretion, the suspended participation of its Eligible Employees eligible to participate in the Plan will be recognized in a manner consistent with Code Section 409A. In the event the respective Participating Subsidiary fails to make such payment or reimbursement, an Eligible Employee’s (or other payee’s) sole recourse shall be against the respective Participating Subsidiary, and not against PG&E CORP. An Eligible Employee’s participation in the Plan shall constitute agreement with this provision.
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(e)    Applicable Law. The provisions of the Plan shall be construed, administered, and enforced in accordance with the laws of the State of California and, to the extent applicable, ERISA. The Plan is intended to comply with the provisions of Code Section 409A. However, PG&E CORP makes no representation that the benefits provided under the Plan will comply with Code Section 409A and makes no undertaking to prevent Code Section 409A from applying to the benefits provided under the Plan or to mitigate its effects on any deferrals or payments made under the Plan.
(f)    Severability. If any provision of the Plan is held invalid or unenforceable, its invalidity or unenforceability shall not affect any other provisions of the Plan, and the Plan shall be construed and enforced as if such provision had not been included.
(g)    Captions. The captions contained in and the table of contents prefixed to the Plan are inserted only as a matter of convenience and for reference and in no way define, limit, enlarge, or describe the scope or intent of the Plan nor in any way shall affect the construction of any provision of the Plan.
15.    Claims and Appeals Procedure. Any claims for benefits under the Plan made by a participant, beneficiary or other person shall be made and administered in accordance with the following procedures.
(a)    Compliance with Regulations. It is intended that the claims procedure of the Plan be administered in accordance with the claims procedure regulations of the U.S. Department of Labor set forth in 29 C.F.R. Section 2560.503-1.
(b)    Initial Claims.
(1)    Submission of Initial Claims by a Claimant. Claims for benefits under the Plan made by a participant, beneficiary or other person covered or claiming they are entitled to benefits from the Plan (a “Claimant”) (or by an authorized representative of any Claimant) must be submitted in writing to the Director, Benefits, or if the title for the position ever changes, the individual employed in Benefits with direct management responsibility over the Plan (whether a Manager or some other title) (such individual, the “Initial Claim Reviewer”), care of Benefits.
(2)    Authorized Representative. The Plan Administrator may establish and enforce reasonable procedures for determining whether any individual or entity has been authorized to act on behalf of a Claimant.
(3)    Processing of Approved Claims. Approved claims will be processed and, if applicable, the Plan Administrator will issue instructions authorizing payments as approved.
(4)    Notification of Denied Claims. If a claim is denied in whole or in part by the Initial Claim Reviewer in its discretion, the Initial Claim Reviewer shall notify the Claimant of the decision by written or electronic notice, in a manner calculated to be understood by the Claimant. The notice shall set forth:
a)    The specific reasons for the denial of the claim;
b)    A reference to specific provisions of the Plan on which the denial is based;
c)    A description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
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d)    An explanation of the Plan’s claims review procedure for the denied or partially denied claim and any applicable time limits, and a statement that the Claimant has a right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review.
Such notification shall be given within 90 days after the claim is received by the Initial Claim Reviewer (or within 180 days, if special circumstances require an extension of time for processing the claim and provided that written notice of such extension and circumstances and the date a decision is expected is given to the Claimant within the initial 90-day period). A claim is considered approved only if its approval is communicated in writing to a Claimant.
(c)    Appeals of Denied Claims.
(1)    Right to Appeal. Upon denial of a claim in whole or in part, a Claimant or his or her duly authorized representative shall have the right to submit a written request to the Employee Benefit Appeals Committee, as such term is defined the Pacific Gas and Electric Company Retirement Plan Part I, as amended and restated from time to time (the “Employee Benefit Appeals Committee”) for a full and fair review of the denied claim. A request for review of a claim must be submitted within 60 days of receipt by the Claimant of written notice of the denial of the claim. If the Claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the Claimant is precluded from reasserting it. Also, if the Claimant is not provided a notice of denial of an initial claim as set forth in Section 15(b), the Claimant may submit a written request for review to the Employee Benefit Appeals Committee.
(2)    Access to Documents and Records. The Claimant or the Claimant’s representative shall have, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits.
(3)    Right to Submit Additional Information. The Claimant may submit written comments, documents, records and other information relating to the claim for benefits.
(4)    Scope of the Review. The Employee Benefit Appeals Committee review process shall include all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
(5)    Preclusion for Materials Not Submitted. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(6)    Decision by the Employee Benefit Appeals Committee. The decision by the Employee Benefit Appeals Committee on review shall be in written or electronic form, in a manner calculated to be understood by the Claimant. If the claim is denied on review, the notice shall set forth:
a)    The specific reasons for the denial of the appeal of the claim;
b)    A reference to specific provisions of the Plan on which the denial is based;
c)    A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and;
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d)    A statement describing any voluntary appeal procedures offered by the Plan (if any) and the Claimant’s right to obtain the information about such procedures, and a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA.
The Employee Benefit Appeals Committee will advise the Claimant of the results of the review within 60 days after receipt of the written request for review (or within 120 days if special circumstances require an extension of time for processing the request, and if notice of such extension and circumstances, including the date a decision is expected to be made, is given to such Claimant within the initial 60-day period).
(d)    Authority of Initial Claim Reviewer and Employee Benefit Appeals Committee and Deference to their Decisions. To the extent of the responsibility to review initial benefit claims (with respect to the Initial Claim Reviewer) or to review appeals of the denial of benefit claims (with respect to the Employee Benefit Appeals Committee), the Initial Claim Reviewer and the Employee Benefit Appeals Committee, shall have the discretionary authority to interpret and apply the provisions of the Plan and such decisions shall be afforded the maximum deference permitted by law. Benefits will be paid only if the Initial Claim Reviewer (with respect to initial benefit claims) or the Employee Benefit Appeals Committee (with respect to appeals of the denial of benefit claims) decides in its discretion that the Claimant is entitled to them. The decisions of the Employee Benefit Appeals Committee shall be final and binding on the Claimant.
(e)    Exhaustion of Claims Procedure Required in All Cases. A participant, beneficiary or other person asserting a claim, alleging a violation of or seeking any remedy under any provision of ERISA or other applicable law that relates in any manner to the Plan is considered a Claimant and is subject to the claims procedures described in this Section 15.
A participant, beneficiary or other person made subject to the claims procedures in this Section 15 must follow and exhaust the applicable claims procedures described in this Section 15 with respect to any claim, alleged violation, or sought remedy before taking action in any other forum regarding a claim for benefits under the Plan or alleging a violation of, or seeking any remedy under, any provision of ERISA or other applicable law.
A Claimant and any representative of a Claimant may not bring an action in any other forum later than the earliest of (1) one year from the date of completion of the Plan’s claims appeal process set forth in this Section 15, (2) one year from the latest date on which an appeal is permitted to be filed under this claims and appeals process after the denial of an initial claim (i.e., within 60 days of receipt of an initial claim denial notification), and (3) two years from the date a Claimant knew or should have known that a claim existed. The foregoing in no way serves as a waiver of the exhaustion requirement set forth in the preceding paragraph.
Any action described in this Section 15(e) must be filed in the Federal District Court for the Northern District of California.
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APPENDIX A
EMPLOYERS
(As of January 1, 2005)


– PG&E Corporation
– All Participating Subsidiaries
Participating Subsidiaries (as of January 1, 2005):
– Pacific Gas and Electric Company
– All U.S. subsidiaries of the above-named corporations





APPENDIX B
INVESTMENT FUNDS
(as of August 1, 2011)


SRSP Target Date Funds are a suite of funds that provides investors with convenient, cost-effective exposure across major global asset classes within single investment options. The suite consists of ten funds targeting a normal retirement age of 65. These broadly diversified vehicles combine low-cost stock and bond strategies and automatic rebalancing with professional judgment regarding the appropriate risk level for a specific retirement date. On an annual basis, the SRSP Target Date Funds incrementally reduce exposure to equities and increase exposure to fixed income assets as the target retirement date approaches. This equity roll down continues for five years after the target retirement date, at which time a fixed income-oriented allocation of 65% is combined with 35% stocks that is maintained indefinitely within the RSP Target Retirement Income Fund. A participant typically invests in one fund within the suite which fund reflects a target retirement date closest to the anticipated retirement date of the participant.

PG&E Corporation Phantom Stock Fund converts contributions and transferred amounts into units of phantom common stock valued at the closing price of a share of PG&E Corporation common stock on the contribution/transfer date. If the transfer request is received after the market closes, the following day’s closing price will be used. Thereafter, the value of a unit shall fluctuate depending on the price of PG&E Corporation common stock. Each time a dividend is paid on common stock, an amount equal to such dividend shall be credited to the account as additional units.

SRSP Total US Stock Index Fund seeks to match the returns of the Russell 3000 Index. The Russell 3000 Index represents the 3,000 largest stocks in the US market and accounts for approximately 97% of the US stock market’s capitalization. The strategy of investing in the same stocks as the Russell 3000 Index provides reliable exposure to this asset class and results in lower expenses.

SRSP Large Company Stock Index Fund seeks to match the returns of the S&P 500 Index. The Fund invests in all 500 stocks in the S&P 500 Index in proportion to their weightings in the Index. The S&P 500 provides exposure to about 85% of the market value of all publicly traded common stocks in the United States. The strategy of investing in the same stocks as the S&P 500 Index provides reliable exposure to this asset class and results in lower expenses.

SRSP Small Company Stock Index Fund seeks to match the returns of the Russell Small Cap Completeness Index. The Fund invests in all of the stocks in the Russell Special Small Cap Completeness Index in proportion to their weightings in the Index. The Russell Small Cap Completeness Index represents about 15% of the market value of all publicly traded common stocks in the United States. The strategy of investing in the same stocks as the Russell Small Cap Completeness Index provides reliable exposure to this asset class and results in lower expenses.

SRSP World Stock Index Fund seeks to match the returns of the MSCI All Country World Index over the long term. The MSCI All Country World Index invests in the US, Canada, Europe, Australasia and Far East countries and emerging markets. The strategy of investing in a portfolio of stocks designed to track the MSCI All Country World Ex-US Index provides reliable exposure to this asset class and results in lower expenses.



SRSP International Stock Index Fund seeks to match the returns of the MSCI World ex-US Index. The Fund invests in all of the stocks in the MSCI World ex-US Index in proportion to their weightings in the Index. The MSCI World ex-US index provides exposure to Canada as well as developed market countries in Europe, Australasia, and the Far East. The strategy of investing in the same stocks as the MSCI World ex-US provides reliable exposure to this asset class and results in lower expenses.

SRSP Emerging Markets Enhanced Index Fund seeks to provide a total investment return in excess of the performance of the MSCI Emerging Markets Index over the long term. The MSCI Emerging Markets Index invests in emerging market countries. The strategy attempts to identify and capitalize on inefficiencies in the emerging markets by employing a disciplined investment process that combines top-down country selection with bottom-up stock selection to determine an optimal country and security mix. Portfolio construction is risk-controlled, with the goal of a well-diversified portfolio that has characteristics similar to the benchmark and superior performance potential.

SRSP Bond Index Fund seeks to match the returns of the Barclays Capital Aggregate Bond Index. The Fund invests in a portfolio of government, corporate, mortgage-backed, and asset-backed fixed-income securities that is representative of the broad domestic bond market. The Barclays Capital Aggregate Bond Index is an unmanaged, market-value weighted index of investment-grade, fixed-rate debt issues, including government, corporate, asset-backed, and mortgage-backed securities, with maturities of one year or more. The strategy of investing in a portfolio of bonds designed to track the Barclays Capital Aggregate Bond Index provides reliable exposure to this asset class and results in lower expenses.

SRSP US Government Bond Index Fund seeks to match the returns of the Barclays Capital US Government Bond Index. The Fund invests in a well-diversified portfolio that is representative of the Barclays Capital US Government Bond Index, which consists of US Government and government agency securities (other than mortgage securities) with maturities of one year or more. The strategy of investing in a portfolio of stocks designed to track the Barclays Capital US Government Index provides reliable exposure to this asset class and results in lower expenses.

SRSP Money Market Investment Fund is maintained for the purpose of investing in a diversified portfolio consisting primarily of short-term government and non-government debt securities. The primary objective of this fund is to provide participants with preservation of principal.

Short-Term Bond Index Fund is maintained for the purpose of investing in a diversified portfolio consisting primarily of short-term, marketable fixed-income securities.
AA Utility Bond Fund accrues interest on the amount invested in this fund. The interest rate is equal to the AA Utility Bond Yield reported by Moody’s Investor Services.








PG&E CORPORATION
2005 SUPPLEMENTAL RETIREMENT SAVINGS PLAN

EXHIBIT 10.4

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
OF
PG&E CORPORATION
(As Amended Effective as of September 12, 2023)

______________________________________________

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

    No new participants can become eligible to accrue benefits under the PLAN on or after January 1, 2013, and existing participants in the PLAN as of January 1, 2013 shall cease to accrue further benefits under the Plan as of the date they become participants in Part III of the RETIREMENT PLAN. This Plan was further amended effective June 3, 2019 to reflect incentive structures adopted in connection with the CORPORATION’s and the COMPANY’s voluntary petition filed on January 29, 2019 pursuant to chapter 11 of title 11 of the U.S. Bankruptcy Code. This Plan was further amended effective September 12, 2023 to add claims and appeals procedures.

ARTICLE 1

DEFINITIONS
1.01    Basic SERP Benefit shall mean the benefit described in Section 2.01.
1.02    Board or Board of Directors shall mean the BOARD OF DIRECTORS of the CORPORATION or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN.
1.03    Company shall mean the Pacific Gas and Electric Company, a California corporation.
1.04    Corporation shall mean PG&E Corporation, a California corporation.
1.05    Eligible Employee shall mean individuals who are, prior to January 1, 2013 (1) (a) employees of the COMPANY or, with respect to PG&E Corporation, PG&E Corporation Support Services, Inc., and PG&E Corporation Support Services II, Inc. only, (i) prior to April 1, 2007, were employees who transferred to PG&E Corporation, PG&E Corporation Support Services, Inc., or PG&E Corporation Support Services II, Inc. from Pacific Gas and Electric Company; or (ii) after March 31, 2007, all employees, and (b) officers in Officer Bands I-V, or (2) such other employees of the COMPANY, the CORPORATION, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., or such other companies, affiliates, subsidiaries, or associations, as may be designated by the Chief Executive Officer of the CORPORATION. ELIGIBLE EMPLOYEES shall not include employees who retired prior to January 1, 2005, or whose employment relationship with any of the PARTICIPATING EMPLOYERS was otherwise terminated prior to January 1, 2005.
1    Words in all capitals are defined in Article I.





1.06    STIP Payment shall mean amounts received by an ELIGIBLE EMPLOYEE under the Short-Term Incentive Plan or other short-term or annual performance-based cash incentive plan (e.g., the 2019 Key Employee Incentive Plan) maintained by the CORPORATION prior to the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.
1.07    PART III of the RETIREMENT PLAN shall mean the cash balance benefit available under the RETIREMENT PLAN.
1.08    Participating Employer shall mean the COMPANY, the CORPORATION, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., and any other companies, affiliates, subsidiaries or associations designated by the Chief Executive Officer of the CORPORATION.
1.09    Plan shall mean the Supplemental Executive Retirement Plan (“SERP”) as set forth herein and as may be amended from time to time.
1.010    Plan Administrator shall mean the Employee Benefit Committee or such individual or individuals as that Committee may appoint to handle the day-to-day affairs of the PLAN.
1.10    Retirement Plan shall mean the Pacific Gas and Electric Company Retirement Plan.
1.11    Salary shall mean the base salary received by an ELIGIBLE EMPLOYEE prior to the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN. SALARY shall not include amounts received by an employee after such employee ceases to be an ELIGIBLE EMPLOYEE. For purposes of calculating benefits under the PLAN, SALARY shall not be reduced to reflect amounts that have been deferred under the PG&E Corporation Supplemental Retirement Savings Plan.
1.12    Service shall mean “credited service” as that term is defined in the RETIREMENT PLAN or, if the Nominating and Compensation Committee of the BOARD OF DIRECTORS has granted an adjusted service date for an ELIGIBLE EMPLOYEE, “credited service” as calculated from such adjusted service date. In no event, however, shall SERVICE include periods of time after which an officer has ceased to be an ELIGIBLE EMPLOYEE or after the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.
ARTICLE 2

SERP BENEFITS
2.01    The BASIC SERP BENEFIT payable from the PLAN shall be a monthly annuity with an annuity start date of the later of (a) the first of the month following the month in which the ELIGIBLE EMPLOYEE has a separation from service (as provided under Code Section 409A and related guidance), or (b) the first of the month following the ELIGIBLE EMPLOYEE’s 55th birthday; provided, however, that no payments under the PLAN shall be made until the seventh month following the annuity start date. The first payment shall consist of the monthly annuity payment for the seventh month, plus the first six monthly annuity payments, including interest calculated at a rate to reflect the CORPORATION’s marginal cost of funds. The monthly amount of the BASIC SERP BENEFIT shall be equal to the product of:
1.7% x the average of three highest calendar years’ combination of SALARY and STIP PAYMENT for the last ten years of SERVICE x SERVICE x 1/12.

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

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

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

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

2.02    For ELIGIBLE EMPLOYEES of the PARTICIPATING EMPLOYERS, who transfer from any of said companies to another subsidiary or affiliate, the principles of Section 10 of the RETIREMENT PLAN shall govern the calculation of benefits under this PLAN.
2.03    An ELIGIBLE EMPLOYEE may elect to have his BASIC SERP BENEFIT paid in any one of the following forms that are actuarially equivalent within the meaning of Treasury Regulations Section 1.409A-2(b)(ii), with the first annuity payment commencing at the time set forth in Section 2.01:
(a)    BASIC SERP BENEFIT, or a reduced BASIC SERP BENEFIT as calculated under Section 2.02, paid as a monthly annuity for the life of the ELIGIBLE EMPLOYEE with no survivor’s benefit.
(b)    A monthly annuity payable for the life of the ELIGIBLE EMPLOYEE with a survivor’s option payable to the ELIGIBLE EMPLOYEE’s joint annuitant beginning on the first of the month following the ELIGIBLE EMPLOYEE’s death. Subject to the requirements of Treasury Regulations Section 1.409A-2(b)(ii), the factors to be applied to reduce the BASIC SERP BENEFIT to provide for a survivor’s benefit shall be the factors which are contained in the RETIREMENT PLAN and which are appropriate given the type of joint pension elected and the ages and marital status of the joint annuitants.
An ELIGIBLE EMPLOYEE may make this election by the latest date permitted by the PLAN ADMINISTRATOR and in compliance with the rules of Treasury Regulations Section 1.409A-2(b)(2)(ii).

2.04    Annuities payable to an ELIGIBLE EMPLOYEE who is receiving a (i) BASIC SERP BENEFIT, (ii) a BASIC SERP BENEFIT reduced to provide a survivor’s benefit to a joint annuitant, or (iii) a joint annuitant who is receiving a survivor’s benefit shall be decreased by any additional amounts which can be paid from the RETIREMENT PLAN where such additional amounts are due to increases in the limits placed on benefits payable from qualified pension plans under Section 4l5 of the Internal Revenue Code. The amount of any such decrease shall be adjusted to reflect the type of pension elected by an ELIGIBLE EMPLOYEE under the RETIREMENT PLAN and this PLAN.
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ARTICLE 3

SURVIVOR BENEFITS
3.01    In the event that an ELIGIBLE EMPLOYEE who has accrued a benefit under this PLAN dies prior to the date that a BASIC SERP BENEFIT would otherwise commence, the PLAN ADMINISTRATOR shall pay a survivor’s benefit (“SURVIVOR’S BENEFIT”) to the ELIGIBLE EMPLOYEE’s surviving spouse or BENEFICIARY (“Beneficiary” shall have the same meaning as provided under the RETIREMENT PLAN):
(a)    If the sum of the age and SERVICE of the ELIGIBLE EMPLOYEE at the time of death equaled 70 (69.5 or more is rounded to 70) or if the ELIGIBLE EMPLOYEE was age 55 or older at the time of death, the surviving spouse’s or BENEFICIARY’s benefit shall be a monthly annuity commencing at the time set forth in Section 2.01 and shall be payable for the life of the surviving spouse or BENEFICIARY. The amount of the monthly benefit shall be a monthly benefit that is actuarially equivalent to one-half of the monthly BASIC SERP BENEFIT that would have been paid to the ELIGIBLE EMPLOYEE calculated:
(i)    as if he had elected to receive a BASIC SERP BENEFIT, without survivor’s option; and
(ii)    the monthly annuity starting date was the first of the month following the month in which the ELIGIBLE EMPLOYEE died; and
(iii)    without the application of early retirement reduction factors. However, if the surviving spouse or BENEFICIARY is more than 10 years younger than the ELIGIBLE EMPLOYEE, the amount of the surviving spouse’s or BENEFICIARY’s benefit shall be reduced one-twentieth of 1 percent for each full month in excess of 120 months’ difference in their ages, except that such reduction shall not result in a SURVIVOR’S BENEFIT lower than would have been payable if the ELIGIBLE EMPLOYEE had retired as of the date of death and elected a 50 percent joint pension with a spouse of the same gender and age as the surviving spouse or BENEFICIARY.
(b)    If the ELIGIBLE EMPLOYEE is less than 55 years of age or had fewer than 70 points (as calculated under Section 3.01(a)) at the time of death, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity commencing at the time set forth in Section 2.01. The amount of the monthly annuity payable to the surviving spouse or BENEFICIARY shall be equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if: 1) the ELIGIBLE EMPLOYEE had terminated employment at the date of death, 2) had lived until age 55, 3) had begun to receive PENSION payments at age 55, and 4) had subsequently died.
(c)    If a former ELIGIBLE EMPLOYEE was age 55 or older at the time of his death and not yet receiving a SERP BENEFIT under the PLAN, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity at the time set forth in Section 2.01 in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if the former ELIGIBLE EMPLOYEE had begun receiving the converted SERP BENEFIT immediately prior to his death.
(d)    If a former ELIGIBLE EMPLOYEE was younger than age 55 and had fewer than 70 points (as calculated under Section 3.01(a)) at the time of his death, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity at the time set forth in Section 2.01 in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if: 1) the former ELIGIBLE EMPLOYEE had survived until age 55, 2) had begun receiving the converted SERP BENEFIT at age 55, and 3) had subsequently died.
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3.02    A surviving spouse or BENEFICIARY who is entitled to receive a SURVIVOR’S BENEFIT under Section 3.01 shall not be entitled to receive any other benefit under the PLAN.
ARTICLE 4

ADMINISTRATIVE PROVISIONS
4.01    Administration. The PLAN shall be administered by the Senior Human Resources Officer of the CORPORATION (“PLAN ADMINISTRATOR”), who shall have the authority to interpret the PLAN and make and revise such rules as he or she deems appropriate. The PLAN ADMINISTRATOR shall have the duty and responsibility of maintaining records, making the requisite calculations, and disbursing payments hereunder. The PLAN ADMINISTRATOR’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.
4.02    Amendment and Termination. The CORPORATION may amend or terminate the PLAN at any time, provided, however, that no such amendment or termination shall adversely affect an accrued benefit which an ELIGIBLE EMPLOYEE has earned prior to the date of such amendment or termination, nor shall any amendment or termination adversely affect a benefit which is being provided to an ELIGIBLE EMPLOYEE, surviving spouse, joint annuitant, or beneficiary under Article II or Article III on the date of such amendment or termination. Anything in this Section 4.02 to the contrary notwithstanding, the CORPORATION may (but is not obligated to) reduce or terminate any benefit to which an ELIGIBLE EMPLOYEE, surviving spouse or joint annuitant, is or may become entitled provided that such ELIGIBLE EMPLOYEE, surviving spouse or joint annuitant is or becomes entitled to an amount equal to such benefit under another plan, practice, or arrangement of the CORPORATION that preserves the time and form of payment rules under the PLAN and otherwise in a manner that complies with Code Section 409A, to the extent required to not violate Code Section 409A.
4.03    Nonassignability of Benefits. Except to the extent otherwise directed by a domestic relations order that the Plan Administrator determines is a Qualified Domestic Relations Order under Section 401(a)(12) of the Internal Revenue Code, the benefits payable under this PLAN or the right to receive future benefits under this PLAN may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits becomes bankrupt, the interest under the PLAN of the person affected may be terminated by the PLAN ADMINISTRATOR which, in its sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate.
4.04    Nonguarantee of Employment. Nothing contained in this PLAN shall be construed as a contract of employment between a PARTICPATING EMPLOYER and the ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ of a PARTICIPATING EMPLOYER, to remain as an officer of a PARTICIPATING EMPLOYER, or as a limitation on the right of a PARTICIPATING EMPLOYER to discharge any of its employees, with or without cause.
4.05    Apportionment of Costs. The costs of the PLAN may be equitably apportioned by the PLAN ADMINISTRATOR among the PARTICIPATING EMPLOYERS. Each PARTICIPATING EMPLOYER shall be responsible for making benefit payments pursuant to the PLAN on behalf of its ELIGIBLE EMPLOYEES or for reimbursing the CORPORATION for the cost of such payments, as determined by the CORPORATION in its sole discretion. In the event the respective PARTICIPATING EMPLOYER fails to make such payment or reimbursement, and the CORPORATION does not exercise its discretion to make the contribution on such PARTICIPATING EMPLOYER’s behalf, future benefit accruals of the ELIGIBLE EMPLOYEES of that PARTICIPATING EMPLOYER shall be suspended. If at
5


some future date, the PARTICIPATING EMPLOYER makes all past-due contributions, plus interest at a rate determined by the PLAN ADMINISTRATOR in his or her sole discretion, the benefit accrual of its ELIGIBLE EMPLOYEES will be recognized for the period of the suspension.
4.06    Benefits Unfunded and Unsecured. The benefits under this PLAN are unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such ELIGIBLE EMPLOYEE’s right to receive a distribution of benefits under this PLAN shall be an unsecured claim against the general assets of the CORPORATION.
4.07    Applicable Law. All questions pertaining to the construction, validity, and effect of the PLAN shall be determined in accordance with the laws of the United States, and to the extent not preempted by such laws, by the laws of the State of California. The PLAN is intended to comply with the provisions of Code Section 409A. However, the CORPORATION makes no representation that the benefits provided under this PLAN will comply with Code Section 409A and makes no undertaking to prevent Code Section 409A from applying to the benefits provided under this PLAN or to mitigate its effects on any deferrals or payments made under this PLAN.
4.08    Satisfaction of Claims. Notwithstanding Section 4.05 or any other provision of the PLAN, the CORPORATION may at any time satisfy its obligations (either on a before-tax or after-tax basis) for any benefits accrued under the PLAN by the purchase from an insurance company of an annuity contract on behalf of an ELIGIBLE EMPLOYEE. Such purchase shall be in the sole discretion of the CORPORATION and shall be subject to the ELIGIBLE EMPLOYEE’s acknowledgement that the CORPORATION’s obligations to provide benefits hereunder have been discharged, without regard to the payments ultimately made under the contract. In the event of a purchase pursuant to this Section 4.07, the CORPORATION may in its sole discretion make payments to or on behalf of an ELIGIBLE EMPLOYEE to defray the cost to such ELIGIBLE EMPLOYEE of any personal income tax in connection with the purchase.
ARTICLE 5

CLAIMS AND APPEALS PROCEDURE
Any claims for benefits under the Plan made by a participant, beneficiary or other person shall be made and administered in accordance with the following procedures.
5.01    Compliance with Regulations. It is intended that the claims procedure of the Plan be administered in accordance with the claims procedure regulations of the U.S. Department of Labor set forth in 29 C.F.R. Section 2560.503-1.
5.02    Initial Claims.
(a)    Submission of Initial Claims by a Claimant. Claims for benefits under the Plan made by a participant, beneficiary or other person covered or claiming they are entitled to benefits from the Plan (a “Claimant”) (or by an authorized representative of any Claimant) must be submitted in writing to the Director, Benefits, or if the title for the position ever changes, the individual employed in Benefits with direct management responsibility over the Plan (whether a Manager or some other title) (such individual, the “Initial Claim Reviewer”), care of Benefits.
(b)    Authorized Representative. The Plan Administrator may establish and enforce reasonable procedures for determining whether any individual or entity has been authorized to act on behalf of a Claimant.
(c)    Processing of Approved Claims. Approved claims will be processed and, if applicable, the Plan Administrator will issue instructions authorizing payments as approved.
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(d)    Notification of Denied Claims. If a claim is denied in whole or in part by the Initial Claim Reviewer in its discretion, the Initial Claim Reviewer shall notify the Claimant of the decision by written or electronic notice, in a manner calculated to be understood by the Claimant. The notice shall set forth:
i)    The specific reasons for the denial of the claim;
ii)    A reference to specific provisions of the Plan on which the denial is based;
iii)    A description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
iv)    An explanation of the Plan’s claims review procedure for the denied or partially denied claim and any applicable time limits, and a statement that the Claimant has a right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review.
Such notification shall be given within 90 days after the claim is received by the Initial Claim Reviewer (or within 180 days, if special circumstances require an extension of time for processing the claim and provided that written notice of such extension and circumstances and the date a decision is expected is given to the Claimant within the initial 90-day period). A claim is considered approved only if its approval is communicated in writing to a Claimant.
5.03    Appeals of Denied Claims.
(a)    Right to Appeal. Upon denial of a claim in whole or in part, a Claimant or his or her duly authorized representative shall have the right to submit a written request to the Employee Benefit Appeals Committee, as such term is defined the Pacific Gas and Electric Company Retirement Plan Part I, as amended and restated from time to time (the “Employee Benefit Appeals Committee”) for a full and fair review of the denied claim. A request for review of a claim must be submitted within 60 days of receipt by the Claimant of written notice of the denial of the claim. If the Claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the Claimant is precluded from reasserting it. Also, if the Claimant is not provided a notice of denial of an initial claim as set forth in Section 5.02, the Claimant may submit a written request for review to the Employee Benefit Appeals Committee.
(b)    Access to Documents and Records. The Claimant or the Claimant’s representative shall have, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits.
(c)    Right to Submit Additional Information. The Claimant may submit written comments, documents, records and other information relating to the claim for benefits.
(d)    Scope of the Review. The Employee Benefit Appeals Committee review process shall include all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
(e)    Preclusion for Materials Not Submitted. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(f)    Decision by the Employee Benefit Appeals Committee. The decision by the Employee Benefit Appeals Committee on review shall be in written or electronic form, in a
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manner calculated to be understood by the Claimant. If the claim is denied on review, the notice shall set forth:
i)    The specific reasons for the denial of the appeal of the claim;
ii)    A reference to specific provisions of the Plan on which the denial is based;
(iii)    A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and;
(iv)    A statement describing any voluntary appeal procedures offered by the Plan (if any) and the Claimant’s right to obtain the information about such procedures, and a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA.
The Employee Benefit Appeals Committee will advise the Claimant of the results of the review within 60 days after receipt of the written request for review (or within 120 days if special circumstances require an extension of time for processing the request, and if notice of such extension and circumstances, including the date a decision is expected to be made, is given to such Claimant within the initial 60-day period).
5.04    Authority of Initial Claim Reviewer and Employee Benefit Appeals Committee and Deference to their Decisions. To the extent of the responsibility to review initial benefit claims (with respect to the Initial Claim Reviewer) or to review appeals of the denial of benefit claims (with respect to the Employee Benefit Appeals Committee), the Initial Claim Reviewer and the Employee Benefit Appeals Committee, shall have the discretionary authority to interpret and apply the provisions of the Plan and such decisions shall be afforded the maximum deference permitted by law. Benefits will be paid only if the Initial Claim Reviewer (with respect to initial benefit claims) or the Employee Benefit Appeals Committee (with respect to appeals of the denial of benefit claims) decides in its discretion that the Claimant is entitled to them. The decisions of the Employee Benefit Appeals Committee shall be final and binding on the Claimant.
5.05    Exhaustion of Claims Procedure Required in All Cases. A participant, beneficiary or other person asserting a claim, alleging a violation of or seeking any remedy under any provision of ERISA or other applicable law that relates in any manner to the Plan is considered a Claimant and is subject to the claims procedures described in this Article 5.
A participant, beneficiary or other person made subject to the claims procedures in this Article 12 must follow and exhaust the applicable claims procedures described in this Article 5 with respect to any claim, alleged violation, or sought remedy before taking action in any other forum regarding a claim for benefits under the Plan or alleging a violation of, or seeking any remedy under, any provision of ERISA or other applicable law.
A Claimant and any representative of a Claimant may not bring an action in any other forum later than the earliest of (1) one year from the date of completion of the Plan’s claims appeal process set forth in this Article 5, (2) one year from the latest date on which an appeal is permitted to be filed under this claims and appeals process after the denial of an initial claim (i.e., within 60 days of receipt of an initial claim denial notification), and (3) two years from the date a Claimant knew or should have known that a claim existed. The foregoing in no way serves as a waiver of the exhaustion requirement set forth in the preceding paragraph.
Any action described in this Section 5.05 must be filed in the Federal District Court for the Northern District of California.
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9

EXHIBIT 10.5

PG&E CORPORATION
DEFINED CONTRIBUTION EXECUTIVE SUPPLEMENTAL RETIREMENT PLAN


Effective as of January 1, 2013 (the “Effective Date”), PG&E Corporation adopted this Plan for the benefit of a select group of management or highly compensated employees of PG&E Corporation and its Participating Subsidiaries. This Plan was further amended effective September 17, 2013, with respect to certain vesting and deferral election provisions and effective June 3, 2019 to reflect incentive structures adopted in connection with PG&E Corporation’s and Pacific Gas and Electric Company’s voluntary petition filed on January 29, 2019 pursuant to chapter 11 of title 11 of the U.S. Bankruptcy Code. This Plan was further amended effective January 1, 2022 to reflect changes to officer categorization. This Plan was further amended effective February 15, 2023 with respect to when contribution payments are made under the Plan. This Plan was further amended effective September 12, 2023 to add Article 12 - Claims and Appeals Procedure. The Plan is an unfunded arrangement and is intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of ERISA.

Article 1 – Definitions

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

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

1.02    “Aggregated Plan” means any arrangement that, along with this Plan, would be treated as a single nonqualified deferred compensation plan under Treasury Regulation Section 1.409A-
1(c)(2).

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

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

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

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

1.08    “Eligible Employee” means any individual who (i) was a participant in the SERP and elects to switch under the Pacific Gas and Electric Company Retirement Plan for Management Employees to a cash-balance formula pension benefit effective January 1, 2014, (ii) becomes an Officer with the title of Vice President, Senior Vice President, Executive Vice President, or higher of Company or a Participating Subsidiary on or after the Effective Date; or (iii) is an employee of Company or a Participating Employer, and is designated as a Plan Participant by the Chief
    1    


Executive Officer of Company. Notwithstanding the forgoing, any individual who is a participant in the Excess Plan shall not become an Eligible Employee until January 1 of the calendar year after satisfying any of the criteria in (ii)-(iii) above. If an individual ceases to be an Officer with the title of Vice President, Senior Vice President, Executive Vice President, or higher or if his or her participation in this Plan is terminated by the Chief Executive Officer, then any accrued benefits will be handled in accordance with Article 6.

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

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

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

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

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

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

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

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

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

1.18    “Separation from Service” means a “separation from service” with Company and its
Affiliates within the meaning of Code Section 409A(a)(2)(A)(i) and related Treasury Regulations and other guidance, as determined by the Plan Administrator in its discretion.

1.19    “STIP Payment” means the gross amount of an Eligible Employee’s bonus under the annual cash Short-Term Incentive Plan or other short-term or annual performance-based cash
    2    


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

1.20    “Valuation Date” means:

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

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

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

Article 2 - Company Contributions

2.01    Company Contributions. Company will make a deemed contribution to each Eligible Employee’s Account in a percentage amount designated by the Committee, in its sole discretion, of the Eligible Employee’s Salary and STIP Payment, as soon as practicable, but no more than 30 days after such time that Salary or such STIP Payment is paid.

2.02    Excess Plan Participants. Company will make an additional deemed contribution to the Account of each Eligible Employee who was a participant in the Excess Plan on or after January 1, 2013. The amount of such contribution will be approximately equal to the difference between the amounts that the Eligible Employee could have received under the Plan if contributions, if any, under Section 2.01 had commenced upon satisfying any of the eligibility criteria in Section 1.08(ii)-(iii), and the amount actually accrued under the Excess Plan, in each case through December 31 of such year. Such payments shall be made only for the portion of the calendar year prior to the individual becoming an Eligible Employee. Such calculation shall be done at the Company’s discretion, using such assumptions and methodologies as determined by the Company in its sole discretion. Amounts provided pursuant to this Section will distributed in a lump-sum, in accordance with Section 6.01(2).
Article 3 - Vesting

3.01    Vesting of Company Contributions. Except as otherwise determined by the Plan Administrator in its sole discretion, and provided that the Eligible Employee has not Separated from Service (other than due to death), an Eligible Employee shall become one hundred percent (100%) vested in the Eligible Employee’s Account after completing at least three (3) cumulative years of service with any Employer(s). For this purpose, years of service shall be calculated on an
    3    


elapsed-time, anniversary date of hire basis. “Years of cumulative service” shall include, without limitation, all service while an active participant in the Plan or in the SERP, including active service prior to any break in service. An Employee’s service will be deemed to continue while on approved leave of absence. If an Eligible Employee dies prior to both Separating from Service and satisfying the three-year vesting period, the Eligible Employee’s Account shall vest in full and be paid out in accordance with Section 6.05, below.

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

Article 4 – Investment Funds

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

Article 5 - Accountings

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

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

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

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

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

Article 6 - Distributions

6.01    Distribution of Account Balances.

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

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

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

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

6.03    Timing of Elections.

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

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

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

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

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

6.06    Effect of Change in Eligible Employee Status. If an Eligible Employee ceases to be an Eligible Employee but does not experience a Separation from Service, the balance credited to his
    6    


or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 6.

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

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

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

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

Article 7 - Domestic Relations Orders

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

(1)    No Payment Unless a DRO. No payment shall be made to any person designated in a domestic relations order (an “Alternate Payee”) until the Plan Administrator (or a court of competent jurisdiction reversing an initial adverse determination by the Plan Administrator) determines that the order is a DRO. Payment shall be made to each Alternate Payee as specified in the DRO.
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(2)    Time of Payment. Payment may be made to an Alternate Payee in the form of a lump sum, at the time specified in the DRO, but no earlier than the date the DRO determination is made by the Plan.

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

Article 8 - Tax Withholding

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

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

Article 9 - Administration of the Plan

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

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

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

Article 10 - Modification or Termination of Plan

10.01 Employers’ Obligations Limited. The Plan is voluntary on the part of the Employers, and the Employers do not guarantee to continue the Plan. Company at any time may, by appropriate amendment of the Plan, or suspend Company Contributions , with or without cause.
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10.02    Right to Amend or Terminate. The Board of Directors, acting through the Committee, reserves the right to alter, amend, or terminate the Plan, or any part thereof, in such manner as it may determine, for any reason whatsoever.

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

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

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

Article 11 - General Provisions

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

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

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

11.04.    Apportionment of Costs and Duties. All acts required of the Employers under the Plan may be performed by Company for itself and its Participating Subsidiaries, and the costs of the Plan may be equitably apportioned by the Plan Administrator among Company and the other Employers. Whenever an Employer is permitted or required under the terms of the Plan to do or perform any act, matter or thing, it shall be done and performed by any officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. Each Participating Subsidiary shall be responsible for making benefit payments pursuant to the Plan on behalf of its Eligible Employees or for reimbursing Company for the cost of such payments, as determined by Company in its sole discretion. In the event the respective Participating Subsidiary fails to make such payment or reimbursement, and Company does not exercise its discretion to make the payment on such Participating Subsidiary’s behalf, participation in the Plan by the Eligible Employees of that Participating Subsidiary shall be suspended in a manner consistent with Code Section 409A. If at some future date, the Participating Subsidiary makes all past-due
    9    


payments and reimbursements, plus interest at a rate determined by Company in its sole discretion, the suspended participation of its Eligible Employees eligible to participate in the Plan will be recognized in a manner consistent with Code Section 409A. In the event the respective Participating Subsidiary fails to make such payment or reimbursement, an Eligible Employee’s (or other payee’s) sole recourse shall be against the respective Participating Subsidiary, and not against Company. An Eligible Employee’s participation in the Plan shall constitute agreement with this provision.

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

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

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

Article 12 - Claims and Appeals Procedure

Any claims for benefits under the Plan made by a participant, beneficiary or other person shall be made and administered in accordance with the following procedures.

12.01    Compliance with Regulations. It is intended that the claims procedure of the Plan be administered in accordance with the claims procedure regulations of the U.S. Department of Labor set forth in 29 C.F.R. Section 2560.503-1.
12.02    Initial Claims.
(1)    Submission of Initial Claims by a Claimant. Claims for benefits under the Plan made by a participant, beneficiary or other person covered or claiming they are entitled to benefits from the Plan (a “Claimant”) (or by an authorized representative of any Claimant) must be submitted in writing to the Director, Benefits, or if the title for the position ever changes, the individual employed in Benefits with direct management responsibility over the Plan (whether a Manager or some other title) (such individual, the “Initial Claim Reviewer”), care of Benefits.
(2)    Authorized Representative. The Plan Administrator may establish and enforce reasonable procedures for determining whether any individual or entity has been authorized to act on behalf of a Claimant.
(3)    Processing of Approved Claims. Approved claims will be processed and, if applicable, the Plan Administrator will issue instructions authorizing payments as approved.
(4)    Notification of Denied Claims. If a claim is denied in whole or in part by the Initial Claim Reviewer in its discretion, the Initial Claim Reviewer shall notify the Claimant of the decision by written or electronic notice, in a manner calculated to be understood by the Claimant. The notice shall set forth:
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a)    The specific reasons for the denial of the claim;
b)    A reference to specific provisions of the Plan on which the denial is based;
c)    A description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
d)    An explanation of the Plan’s claims review procedure for the denied or partially denied claim and any applicable time limits, and a statement that the Claimant has a right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review.
Such notification shall be given within 90 days after the claim is received by the Initial Claim Reviewer (or within 180 days, if special circumstances require an extension of time for processing the claim and provided that written notice of such extension and circumstances and the date a decision is expected is given to the Claimant within the initial 90-day period). A claim is considered approved only if its approval is communicated in writing to a Claimant.
12.03    Appeals of Denied Claims.
(1)    Right to Appeal. Upon denial of a claim in whole or in part, a Claimant or his or her duly authorized representative shall have the right to submit a written request to the Employee Benefit Appeals Committee, as such term is defined the Pacific Gas and Electric Company Retirement Plan Part I, as amended and restated from time to time (the “Employee Benefit Appeals Committee”) for a full and fair review of the denied claim. A request for review of a claim must be submitted within 60 days of receipt by the Claimant of written notice of the denial of the claim. If the Claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the Claimant is precluded from reasserting it. Also, if the Claimant is not provided a notice of denial of an initial claim as set forth in Section 12.02, the Claimant may submit a written request for review to the Employee Benefit Appeals Committee.
(2)    Access to Documents and Records. The Claimant or the Claimant’s representative shall have, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits.
(3)    Right to Submit Additional Information. The Claimant may submit written comments, documents, records and other information relating to the claim for benefits.
(4)    Scope of the Review. The Employee Benefit Appeals Committee review process shall include all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
(5)    Preclusion for Materials Not Submitted. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(6)    Decision by the Employee Benefit Appeals Committee. The decision by the Employee Benefit Appeals Committee on review shall be in written or electronic form, in a manner calculated to be understood by the Claimant. If the claim is denied on review, the notice shall set forth:
a)    The specific reasons for the denial of the appeal of the claim;
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b)    A reference to specific provisions of the Plan on which the denial is based;
c)    A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and;
d)    A statement describing any voluntary appeal procedures offered by the Plan (if any) and the Claimant’s right to obtain the information about such procedures, and a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA.
The Employee Benefit Appeals Committee will advise the Claimant of the results of the review within 60 days after receipt of the written request for review (or within 120 days if special circumstances require an extension of time for processing the request, and if notice of such extension and circumstances, including the date a decision is expected to be made, is given to such Claimant within the initial 60-day period).
12.04    Authority of Initial Claim Reviewer and Employee Benefit Appeals Committee and Deference to their Decisions. To the extent of the responsibility to review initial benefit claims (with respect to the Initial Claim Reviewer) or to review appeals of the denial of benefit claims (with respect to the Employee Benefit Appeals Committee), the Initial Claim Reviewer and the Employee Benefit Appeals Committee, shall have the discretionary authority to interpret and apply the provisions of the Plan and such decisions shall be afforded the maximum deference permitted by law. Benefits will be paid only if the Initial Claim Reviewer (with respect to initial benefit claims) or the Employee Benefit Appeals Committee (with respect to appeals of the denial of benefit claims) decides in its discretion that the Claimant is entitled to them. The decisions of the Employee Benefit Appeals Committee shall be final and binding on the Claimant.
12.05    Exhaustion of Claims Procedure Required in All Cases. A participant, beneficiary or other person asserting a claim, alleging a violation of or seeking any remedy under any provision of ERISA or other applicable law that relates in any manner to the Plan is considered a Claimant and is subject to the claims procedures described in this Article 12.
A participant, beneficiary or other person made subject to the claims procedures in this Article 12 must follow and exhaust the applicable claims procedures described in this Article 12 with respect to any claim, alleged violation, or sought remedy before taking action in any other forum regarding a claim for benefits under the Plan or alleging a violation of, or seeking any remedy under, any provision of ERISA or other applicable law.
A Claimant and any representative of a Claimant may not bring an action in any other forum later than the earliest of (1) one year from the date of completion of the Plan’s claims appeal process set forth in this Article 12, (2) one year from the latest date on which an appeal is permitted to be filed under this claims and appeals process after the denial of an initial claim (i.e., within 60 days of receipt of an initial claim denial notification), and (3) two years from the date a Claimant knew or should have known that a claim existed. The foregoing in no way serves as a waiver of the exhaustion requirement set forth in the preceding paragraph.
Any action described in this Section 12.05 must be filed in the Federal District Court for the Northern District of California.


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APPENDIX A
PARTICIPATING SUBSIDIARIES
(As of January 1, 2013)



– Pacific Gas and Electric Company
– All U.S. subsidiaries of PG&E Corporation or the above-named corporation(s)

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EXHIBIT 10.6

PG&E CORPORATION
2012 OFFICER SEVERANCE POLICY
(Amended effective as of September 12, 2023)
1.    Purpose. This is the controlling and definitive statement of the Officer Severance Policy of PG&E Corporation (“Policy”). Since Officers (defined below) are employed at the will of PG&E Corporation (“Corporation”) or a participating employer (“Employer”), their employment may be terminated at any time, with or without cause. A list of Employers is attached hereto as Appendix A. The Policy became effective March 1, 2012, and provides employees with the positions of Vice President, Senior Vice President, Executive Vice President, or higher at the time of termination (“Officers”) of the Corporation and Employers with severance benefits if their employment is terminated.1 The Policy’s definition of Change in Control was amended effective May 12, 2014.2 The Policy’s treatment of STIP payouts and limitations on certain severance payments were added effective September 25, 2020. The value of and eligibility for severance benefits was amended effective November 1, 2021. Appeals and claims procedures were added to the Policy by amendment effective September 12, 2023. For the avoidance of doubt, revisions made to this Policy relating to Code Section 409A (defined below), apply to all Officers including those that may be covered under prior provisions of the Policy as required by Section 7 hereof.
The purpose of the Policy is to attract and retain Officers by defining terms and conditions for severance benefits, to provide severance benefits that are part of a competitive total compensation package, to provide consistent treatment for all terminated officers, and to minimize potential litigation costs associated with Officer termination of employment.
2.    Termination of Employment Not in Connection with Change in Control.
(a)    Corporation or Employer’s Obligations. If the Corporation or an Employer exercises its right to terminate an Officer’s employment without cause and such termination does not entitle Officer to payments under Section 3, the Officer shall be given thirty (30) days’ advance written notice or pay in lieu thereof (which shall be paid in a lump sum together with the payment described in Section 2(a)(1) below). Except as provided in Section 2(c) below, in consideration of the Officer’s agreement to the obligations described in Section 4 below and to the arbitration provisions described in Section 13 below, the following payments and benefits shall also be provided to Officer following Officer’s separation from service (within the meaning of Code Section 409A):3
(1)    A lump sum severance payment equal to the sum of the Officer’s annual base compensation and the Officer’s Short-Term Incentive Plan (“STIP”) target award at the time of his or her termination (the “Severance Base Amount”); provided, however, that for purposes of this section 2(a)(1), any lump sum severance payment for the Corporation’s Chief
1.    Severance benefits for Officers who are currently covered by an employment agreement will continue to be provided solely under such agreements until their expiration at which time this Policy will become effective for such Officers. Specific elements of any Officer’s severance benefits may be amended by appropriate board-level approval. Any Officer’s waiver of benefits under this Policy shall take precedence over the terms of this Policy. If an employee becomes a covered Officer under this Policy as a result of a promotion, and if such Officer was then covered by a severance arrangement subject to Section 409A of the Internal Revenue Code of 1986 (“Code Section 409A”), the severance benefits under this Policy provided to such person shall comply with the time and form of payment provisions of such prior severance arrangement, to the extent required by Code Section 409A.


2    Any payments made hereunder shall be less applicable taxes.


Executive Officer shall be equal to the product of (1) two and (2) such officer’s Severance Base Amount. Annual base compensation shall mean the Officer’s monthly base pay for the month in which the Officer is given notice of termination, multiplied by 12. The payment described in this Section 2(a)(1) shall be made in a single lump sum as soon as practicable following the date the release of claims described in Section 4(a) becomes effective, provided that payment shall in no event be made later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs;
(2)    Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, the equity-based incentive awards granted to Officer under the Corporation’s Long-Term Incentive Program (“LTIP”) which have not yet vested as of the date of termination will continue to vest over a period of twelve months after the date of termination as if the Officer had remained employed for such period. Except as otherwise set forth in the applicable award agreement, for vested stock options as of the date of termination, the Officer shall have the right to exercise such stock options at any time within their respective terms or within five years after termination, whichever is shorter. Except as otherwise set forth in the applicable award agreement, for stock options that vest during a period of twelve months following termination, the Officer shall have the right to exercise such options at any time within one year after termination, subject to the term of the options. Except as otherwise set forth in the applicable award agreement, any unvested equity-based incentive awards remaining at the end of such period shall be forfeited;
(3) A prorated annual incentive payment equal to the annual incentive payment, if any, that the Officer would have earned for the entire calendar year in which the termination occurs pursuant to the Officer’s then-current STIP; based on Eligible Earnings paid between January 1 of such calendar year and the Officer’s date of termination (a “Pro-Rata Incentive”). Subject to Section 14, an Officer’s Pro-Rata Incentive shall be paid by the Officer’s former employer on the date that annual incentive payments are paid to the Employers’ active employees. Notwithstanding the foregoing, the People and Compensation Committee (or its successor) of the Corporation may, decrease, or eliminate the Pro-Rata Incentive for the Officer in its sole discretion. For purposes of this section, “Eligible Earnings” means the sum of the Officer’s: base pay, including paid time off; lump-sum payments as part of a merit increase; temporary assignment pay, including lump-sum payments; and for an Officer on Paid Family Leave or Short-Term Disability, payments made for approved leaves;
(4)    A lump sum cash payment equal to the estimated value of 18 months’of COBRA premiums for the Officer, based on the Officer’s benefit levels at the time of termination (with such payment subject to taxation under applicable law);
(5)    To the extent not theretofore paid or provided, the Officer shall be paid or provided with any other amounts or benefits required to be paid or provided or which the Officer is eligible to receive under any plan, contract, or agreement of the Corporation or Employer; and
(6)    A lump sum cash payment of $19,500, equal to the estimated reasonable value of career transition services for the Officer following separation from service.
(7)    All acts required of the Employer under the Policy may be performed by the Corporation for itself and the Employer, and the costs of the Policy may be equitably apportioned by the Administrator among the Corporation and the other Employers. The Corporation shall be responsible for making payments and providing benefits pursuant to this Policy for Officers employed by the Corporation. Whenever the Employer is permitted or required under the terms of the Policy to do or perform any act, matter or thing, it shall be done and performed by any Officer or employee of the Employer who is thereunto duly authorized by
2


the board of directors of the Employer. Each Employer shall be responsible for making payments and providing benefits pursuant to the Policy on behalf of its Officers or for reimbursing the Corporation for the cost of such payments or benefits, as determined by the Corporation in its sole discretion. In the event the respective Employer fails to make such payment or reimbursement, an Officer’s (or other payee’s) sole recourse shall be against the respective Employer, and not against the Corporation.
(b)    Remedies. An Officer shall be entitled to recover damages for late or nonpayment of amounts to which the Officer is entitled hereunder. The Officer shall also be entitled to seek specific performance of the obligations and any other applicable equitable or injunctive relief.
(c)    Section 2(a) shall not apply in the event that an Officer’s employment is terminated “for cause.” Except as used in Section 3 of this Policy, “for cause” means that the Corporation, in the case of an Officer employed by the Corporation, or Employer in the case of an Officer employed by an Employer, acting in good faith based upon information then known to it, determines that the Officer has engaged in, committed, or is responsible for (1) serious misconduct, gross negligence, theft, or fraud against the Corporation and/or an Employer; (2) refusal or unwillingness to perform his duties; (3) inappropriate conduct in violation of Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationship of the Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty; or (9) any breach of the restrictive covenants contained in Section 4 below. Upon termination “for cause,” the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries shall have no liability to the Officer other than for accrued salary, vacation benefits, and any vested rights the Officer may have under the benefit and compensation plans in which the Officer participates and under the general terms and conditions of the applicable plan.
(d)    The Board of Directors of the Corporation and the Board of Directors of Pacific Gas and Electric Company (the “Utility”) reserve the right to: (a) restrict, limit, cancel, reduce or require forfeiture of payments or benefits pursuant to the provisions of Section 2(a), (i) for any executive officer of the Utility (as defined in California Public Utilities Code § 451.5) or any executive officer of the Corporation (as defined in Rule 3b-7 under the Securities Exchange Act of 1934) in the event of any felony conviction of the Corporation or the Utility related to public health and safety or financial misconduct by the Corporation or the Utility following its July 1, 2020 emergence from Chapter 11 bankruptcy, provided that such executive officer was serving as an executive officer of the Corporation or the Utility, as applicable, at the time of the underlying conduct that led to the conviction (“Company Conviction”), or (ii) for the chief executive officer or chief financial officer of the Corporation or the Utility if that entity is required to prepare a restatement of the financial statement due to the material noncompliance of the Corporation or the Utility, as applicable, with any financial reporting requirement under the federal securities laws, as a result of misconduct, provided that only the payment and benefits under Section 2(a) that the chief executive officer or chief financial officer is eligible to receive during the twelve (12)-month period following the first public issuance or filing with the Securities and Exchange Commission (whichever first occurs) of the financial statement are subject to restriction, limitation, cancellation, reduction or forfeiture and further provided the executive officer was serving as a chief executive officer or chief financial officer of the Corporation or the Utility, as applicable, during the period for which the financial statement is restated; and (b) recoup or require reimbursement or repayment of rights, payments, and benefits under Section 2(a) for any executive officer of the Utility (as defined in California Public Utilities Code § 451.5) or any executive officer of the Corporation (as defined in Rule 3b-7 under
3


the Securities Exchange Act of 1934) in the event such executive officer engaged in misconduct that materially contributed to some of the actions or omissions on which the Company Conviction is based (as determined by the applicable Board in its discretion). The Corporation, the Utility, their affiliates, and their respective directors, officers, and employees shall have no liability to any such executive officer, including the chief executive officer and chief financial officer of the Corporation or the Utility, in the event of restriction, limitation, reduction, recoupment, forfeiture, reimbursement, or cancellation of the provisions of Section 2(a), other than for accrued salary, vacation benefits, and any vested rights such executive officer may have under the benefit and compensation plans in which the executive officer participates and under the general terms and conditions of the applicable plan.
3.    Termination of Employment In Connection With a Change in Control.
(a)    If an Executive Officer’s (defined below) employment by the Corporation or any subsidiary or successor of the Corporation shall be subject to an Involuntary Termination within the Covered Period, then the provisions of this Section 3 instead of Section 2 shall govern the obligations of the Corporation as to the payments and benefits it shall provide to the Executive Officer. In the event that Executive Officer’s employment with the Corporation or an employing subsidiary is terminated under circumstances which would not entitle Executive Officer to payments under this Section 3, Executive Officer shall only receive such benefits to which he is entitled under Section 2, if any. In no event shall Executive Officer be entitled to receive termination benefits under both this Section 3 and Section 2.
All the terms used in this Section 3 shall have the following meanings:
(1)    “Affiliate” shall mean any entity which owns or controls, is owned or is under common ownership or control with, the Corporation.
(2)    “Cause” shall mean (i) the willful and continued failure of the Executive Officer to perform substantially the Executive Officer’s duties with the Corporation or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive Officer by the Board of Directors or the Chief Executive Officer of the Corporation which specifically identifies the manner in which the Board of Directors or Chief Executive Officer believes that the Executive Officer has not substantially performed the Executive Officer’s duties; or (ii) the willful engaging by the Executive Officer in illegal conduct or gross misconduct which is materially demonstrably injurious to the Corporation.
For purposes of the provision, no act or failure to act, on the part of the Executive Officer, shall be considered “willful” unless it is done, or omitted to be done, by the Executive Officer in bad faith or without reasonable belief that the Executive Officer’s action or omission was in the best interests of the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer or a senior officer of the Corporation or based upon the advice of counsel for the Corporation shall be conclusively presumed to be done, or omitted to be done, by the Executive Officer in good faith and in the best interests of the Corporation. The cessation of employment of the Executive Officer shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive Officer a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of Directors at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Executive Officer and the Executive Officer is given an opportunity, together with counsel, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Executive Officer is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.
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(3)    “Change in Control” shall mean the occurrence of any of the following:
a.    any “person” (as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 (“Exchange Act”), but excluding any benefit plan for employees or any trustee, agent or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Exchange Act) of securities of the Corporation representing thirty percent (30%) or more of the combined voting power of the Corporation’s then outstanding voting securities; or
b.    during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors of the Corporation (“Board”) cease for any reason to constitute at least a majority of the Board, unless the election, or the nomination for election by the shareholders of the Corporation, of each new member of the Board (“Director”) was approved by a vote of at least two-thirds (2/3) of the Directors then still in office (1) who were Directors at the beginning of the period or (2) whose election or nomination was previously so approved; or
c.    the consummation of any consolidation or merger of the Corporation other than a merger or consolidation which would result in the holders of the voting securities of the Corporation outstanding immediately prior thereto continuing to directly or indirectly hold at least seventy percent (70%) of the Combined Voting Power of the Corporation, the surviving entity in the merger or consolidation or the parent of such surviving entity outstanding immediately after the merger or consolidation; or
d.    (1) the consummation of any sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Corporation or (2) the approval of the shareholders of the Corporation of a plan of liquidation or dissolution of the Corporation.
(4)    “Change in Control Date” shall mean the date on which a Change in Control occurs.
(5)    “Combined Voting Power” shall mean the combined voting power of the Corporation’s or other relevant entity’s then outstanding voting securities.
(6)    “Covered Period” shall mean the period commencing three months prior to the Change in Control Date and terminating two (2) years following said Change in Control Date.4
(7)    “Disability” shall mean the absence of the Executive Officer from the Executive Officer’s duties with the Corporation or the employing subsidiary on a full-time basis for 180 consecutive business days as a result of incapacity due to physical or mental illness which is determined to be total and permanent by a physician selected by the Corporation or its insurers and acceptable to the Executive Officer or the Executive Officer’s legal representative.
(8)    “Executive Officer” shall mean officers of the Corporation or an Employer with titles of Senior Vice President, Executive Vice President, or higher at time of Involuntary Termination.
4     For a period of three years following notification of this definition of “Covered Period,” Executive Officers who were eligible for benefits under Section 3 as of November 1, 2021, will continue to be subject to the defintion of “Covered Period” as set forth in the Policy as effective September 24, 2020.
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(9)    “Good Reason” shall mean any one or more of the following which takes place within the Covered Period:
            a.    A material diminution in the Executive Officer’s base compensation;

            b.    A material diminution in the Executive Officer’s authority, duties, or responsibilities;

            c.    A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive Officer is required to report, including a requirement that the Executive Officer report to a corporate officer or employee instead of reporting directly to the Board of Directors of the Corporation (in the case of an Executive Officer reporting to such Board of Directors);

            d.    A material diminution in the budget over which the Executive Officer retains authority;

            e.    A material change in the geographic location at which the Executive Officer must perform the services; or

            f.    Any other action or inaction that constitutes a material breach by the Corporation of this Policy;

provided, however, that the Executive Officer must provide notice to the Corporation of the existence of the applicable condition described in this Section 3(a)(9) within 90 days of the initial existence of the condition, upon the notice of which the Corporation shall have 30 days during which it may remedy the condition and, if remedied, Good Reason shall not exist.

(10)     “Involuntary Termination” shall mean a termination (i) by the Corporation (including an employing subsidiary) without Cause, or (ii) by Executive Officer following Good Reason; provided, however, the term "Involuntary Termination" shall not include termination of Executive Officer’s employment due to Executive Officer’s death, Disability, or voluntary retirement.
(11)    “Reference Salary” shall mean the greater of (i) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the date of Executive Officer’s Involuntary Termination, or (ii) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the Change in Control Date.
(12)    “Termination Date” shall be the date specified in the written notice of termination of Executive Officer’s employment given by either party in accordance with Section 3(b) of this Policy.
(b)    Notice of Termination. During the Covered Period, in the event that the Corporation (including an employing subsidiary) or Executive Officer terminates Executive Officer’s employment with the Corporation or Employer, the party terminating employment shall give written notice of termination to the other party, specifying the Termination Date and the specific termination provision in this Section 3 that is relied upon, if any, and setting forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive Officer’s employment under the provision so indicated. The Termination Date shall be determined as follows: (i) if Executive Officer’s employment is terminated for Disability, thirty (30) days after a Notice of Termination is given (provided that Executive Officer shall not
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have returned to the full-time performance of Executive Officer’s duties during such 30-day period); (ii) if Executive Officer’s employment is terminated by the Corporation in an Involuntary Termination, thirty days after the date the Notice of Termination is received by Executive Officer (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below); and (iii) if Executive Officer’s employment is terminated by the Corporation for Cause (as defined in this Section 3), the date specified in the Notice of Termination, provided, that the events or circumstances cited by the Board of Directors as constituting Cause are not cured by Executive Officer during any cure period that may be offered by the Board of Directors. The Termination Date for a resignation of employment other than for Good Reason shall be the date set forth in the applicable notice, which shall be no earlier than ten (10) days after the date such notice is received by the Corporation, unless waived by the Corporation.

During the Covered Period, a notice of termination given by Executive Officer for Good Reason shall be given within 90 days after occurrence of the event on which Executive Officer bases his notice of termination and shall provide a Termination Date of thirty (30) days after the notice of termination is given to the Corporation (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below).
(c)     Corporation’s Obligations. If Executive Officer separates from service due to an Involuntary Termination within the Covered Period, then the Corporation shall provide to Executive Officer the following benefits:
(1)    The Corporation shall pay to the Executive Officer a lump sum in cash within thirty (30) days after the later of the Change in Control Date or the Executive Officer’s separation from service:
a.    the sum of (1) any earned but unpaid base salary through the Termination Date at the rate in effect at the time of the notice of termination to the extent not theretofore paid; (2) the Executive Officer’s target bonus under the STIP of the Corporation, an Affiliate, or a predecessor, for the fiscal year in which the Termination Date occurs (the “Target Bonus”), pro-rated to reflect service during that year; and (3) any accrued but unpaid vacation pay, in each case to the extent not theretofore paid;
b.    the amount equal to the product of (1) two and (2) the sum of (x) the Reference Salary and (y) the Target Bonus; provided, however, that for the Corporation’s Chief Executive Officer, such amount shall be equal to the product of (1) three and (2) the sum of (x) the Reference Salary and (y) the Target Bonus;
c.    a lump sum cash payment equal to the estimated value of 18 months’of COBRA premiums for the Executive Officer, based on the Executive Officer’s benefit levels at the time of termination (with such payment subject to taxation under applicable law), if any; and
d.    a lump sum cash payment of $19,500, equal to the estimated reasonable value of career transition services for the Officer following separation from service.
(2)    Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, in the event of involuntary termination in connection with a Change in Control in which equity-based awards granted to the Executive Officer under the LTIP are not assumed or continued, Executive Officer’s then-outstanding awards that are not vested shall immediately vest in full, and all performance conditions associated with performance-based LTIP awards shall be deemed satisfied as if target performance was achieved,
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and shall be settled in cash, shares or a combination thereof, as determined by the People and Compensation Committee (or its successor), within thirty (30) days following such Change in Control (except to the extent that settlement of the award must be made pursuant to its original schedule in order to comply with Code Section 409A), notwithstanding that the applicable performance period, retention period or other restrictions and conditions have not been completed or satisfied.
(3)    Remedies. The Executive Officer shall be entitled to recover damages for late or nonpayment of amounts which the Corporation is obligated to pay hereunder. The Executive Officer shall also be entitled to seek specific performance of the Corporation’s obligations and any other applicable equitable or injunctive relief.
(d)    Adjustment for Excise Taxes.
(1) “Best-Net Provision”
Subject to Section 3(d)(2) below, in the event that the payments and other benefits provided for in this Policy or otherwise payable to Executive Officer (i) constitute “parachute payments” within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”) and (ii) would be subject to the excise tax imposed by Section 4999 of the Code, then Executive Officer’s payments and benefits under this Policy or otherwise payable to Executive Officer outside of this Policy shall be either delivered in full (without the Corporation paying any portion of such excise tax), or delivered as to 2.99 times of Executive's base amount (within the meaning of Section 280G of the Code) so as to result in no portion of such payments and benefits being subject to such excise tax, whichever of the foregoing amounts, taking into account the applicable federal, state and local income taxes and such excise tax, results in the receipt by Executive Officer on an after-tax basis of the greatest amount of payments and benefits, notwithstanding that all or some portion of such payments and benefits may subject to such excise tax. Unless the Corporation and Executive Officer otherwise agree in writing, any determination required under this Section 3(d)(1) shall be made in writing by Deloitte & Touche (the “Accounting Firm”), whose determination shall be conclusive and binding upon Executive Officer and the Corporation for all purposes. For purposes of making the calculations required by this Section 3(d)(1), the Accounting Firm may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of Section 280G and 4999 of the Code. The Corporation and Executive Officer shall furnish to the Accounting Firm such information and documents as the Accounting Firm may reasonably request in order to make a determination under this Section 3(d)(1).

Any reduction in payments and/or benefits shall occur in the following order as reasonably determined by the Accounting Firm: (1) reduction of cash payments, (2) reduction of non-cash/non-equity-based payments or benefits, and (3) reduction of vesting acceleration of equity-based awards; provided, however, that any non-taxable payments or benefits shall be reduced last in accordance with the same categorical ordering rule.  In the event items described in (1) or (2) are to be reduced, reduction shall occur in reverse chronological order such that the payment or benefit owed on the latest date following the occurrence of the event triggering the excise tax will be the first payment to be reduced (with reductions made pro-rata in the event payments are owed at the same time).  In the event that acceleration of vesting of equity-based awards is to be reduced, such acceleration of vesting shall be cancelled in a manner such as to obtain the best economic benefit for the officer (with reductions made pro-rata if economically equivalent), as determined by the Accounting Firm.
4.    Obligations of Officer.
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(a)    Release of Claims. There shall be no obligation to commence the payment of the amounts and benefits described in Section 2(a) or Section 3(c) (as applicable) until the latter of (1) the delivery by Officer to the Corporation a fully executed comprehensive general release of any and all known or unknown claims that he or she may have against the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries and a covenant not to sue in the form prescribed by the Administrator, and (2) the expiration of any revocation period set forth in the release. The Corporation shall promptly furnish such release to Officer in connection with the Officer’s separation from service, and such release must be executed by Officer and become effective during the period set forth in the release as a condition to Officer receiving the payments and benefits described in Section 2(a) or Section 3(c) (as applicable).
(b)    Covenant Not to Compete. (i) During the period of Officer’s employment with the Corporation or its subsidiaries and for a period of twelve (12) months thereafter (the “Restricted Period”), Officer shall not, in any county within the State of California or in any city, county or area outside the State of California within the United States or in the countries of Canada or Mexico, directly or indirectly, whether as partner, employee, consultant, creditor, shareholder, or other similar capacity, promote, participate, or engage in any activity or other business competitive with the Corporation’s business or that of any of its subsidiaries or affiliates, without the prior written consent of the Corporation’s Chief Executive Officer. Notwithstanding the foregoing, Officer may have an interest in any public company engaged in a competitive business so long as Officer does not own more than 2 percent of any class of securities of such company, Officer is not employed by and does not consult with, or becomes a director of, or otherwise engage in any activities for, such competing company.
(1)    The Corporation and its subsidiaries presently conduct their businesses within each county in the State of California and in areas outside California that are located within the United States, and it is anticipated that the Corporation and its subsidiaries will also be conducting business within the countries of Canada and Mexico. Such covenants are necessary and reasonable in order to protect the Corporation and its subsidiaries in the conduct of their businesses. To the extent that the foregoing covenant or any provision of this Section4(b)(1) shall be deemed illegal or unenforceable by a court or other tribunal of competent jurisdiction with respect to (i) any geographic area, (ii) any part of the time period covered by such covenant, (iii) any activity or capacity covered by such covenant, or (iv) any other term or provision of such covenant, such determination shall not affect such covenant with respect to any other geographic area, time period, activity or other term or provision covered by or included in such covenant.
(c)    Soliciting Customers and Employees. During the Restricted Period, Officer shall not, directly or indirectly, solicit or contact any customer or any prospective customer of the Corporation or its subsidiaries or affiliates for any commercial pursuit that could be reasonably construed to be in competition with the Corporation, or induce, or attempt to induce, any employees, agents or consultants of or to the Corporation or any of its subsidiaries or affiliates to do anything from which Officer is restricted by reason of this covenant nor shall Officer, directly or indirectly, offer or aid to others to offer employment to, or interfere or attempt to interfere with any employment, consulting or agency relationship with, any employees, agents or consultants of the Corporation, its subsidiaries and affiliates, who received compensation of $75,000 or more during the preceding six (6) months, to work for any business competitive with any business of the Corporation, its subsidiaries or affiliates.
(d)    Confidentiality. Officer shall not at any time (including after termination of employment) divulge to others, use to the detriment of the Corporation or its subsidiaries or affiliates, or use in any business competitive with any business of the Corporation or its subsidiaries or affiliates any trade secret, confidential or privileged information obtained during his employment with the Corporation or its subsidiaries or affiliates, without first obtaining the
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written consent of the Corporation’s Chief Executive Officer. This paragraph covers but is not limited to discoveries, inventions (except as otherwise provided by California law), improvements, and writings, belonging to or relating to the affairs of the Corporation or of any of its subsidiaries or affiliates, or any marketing systems, customer lists or other marketing data. Officer shall, upon termination of employment for any reason, deliver to the Corporation all data, records and communications, and all drawings, models, prototypes or similar visual or conceptual presentations of any type, and all copies or duplicates thereof, relating to all matters contemplated by this paragraph.
(e)    Assistance in Legal Proceedings. During the Restricted Period, Officer shall, upon reasonable notice from the Corporation, furnish information and proper assistance (including testimony and document production) to the Corporation as may be reasonably required by the Corporation in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of the Corporation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Corporation shall pay all reasonable expenses incurred by Officer in complying with this paragraph within 60 days after Officer incurs such expenses.
(f)    Remedies. Upon Officer’s failure to comply with the provisions of this Section 4, the Corporation shall have the right to immediately terminate any unpaid amounts or benefits described in Section 2(a) or Section 3 (as applicable) to Officer. In the event of such termination, the Corporation shall have no further obligations under this Policy and shall be entitled to recover damages. In the event of an Officer’s breach or threatened breach of any of the covenants set forth in this Section 4, the Corporation shall also be entitled to specific performance by Officer of any such covenant and any other applicable equitable or injunctive relief.
5.    Administration. The Policy shall be administered by the Senior Human Resources Officer of the Corporation (“Administrator”), who shall have the authority to interpret the Policy and make and revise such rules as may be reasonably necessary to administer the Policy. The Administrator shall have the duty and responsibility of maintaining records, making the requisite calculations, securing Officer releases, and disbursing payments hereunder. The Administrator’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.
6.    No Mitigation. Payment of the amounts and benefits under Section 2(a) and Section 3 (except as otherwise provided in Section 2(a)(5)) shall not be subject to offset, counterclaim, recoupment, defense or other claim, right or action which the Corporation or an Employer may have and shall not be subject to a requirement that Officer mitigate or attempt to mitigate damages resulting from Officer’s termination of employment.
7.    Amendment and Termination. The Corporation, acting through its People and Compensation Committee (or its successor), reserves the right to amend or terminate the Policy at any time; provided, however, that any amendment which would reduce the aggregate level of benefits, or terminate the Policy, shall not become effective prior to the completion of the Notice Period. Such Notice Period shall be the first anniversary of the Corporation giving notice to Officers of such amendment or termination.5
8.    Successors. The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets
5     To the extent that Officers are eligible for benefits until this Policy as of November 1, 2021, the Notice Period shall be three years from the receipt of notice that the Notice Period has been reduced to one year.
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of the Corporation expressly to assume and to agree to perform its obligations under this Policy in the same manner and to the same extent that the Corporation would be required to perform such obligations if no such succession had taken place; provided, however, that no such assumption shall relieve the Corporation of its obligations hereunder. As used herein, the “Corporation” shall mean the Corporation as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform its obligations by operation or law or otherwise.
This Policy shall inure to the benefit of and be binding upon the Officer (and Officer’s personal representatives and heirs), Corporation and its successors and assigns, and any such successor or assignee shall be deemed substituted for the Corporation under the terms of this Policy for all purposes. As used herein, “successor” and “assignee” shall include any person, firm, corporation or other business entity which at any time, whether by purchase, merger or otherwise, directly or indirectly acquires the stock of the Corporation or to which the Corporation assigns this Policy by operation of law or otherwise. If Officer should die while any amount would still be payable to Officer hereunder if Officer had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with this Policy to Officer’s devisee, legatee or other designee, or if there is no such designee, to Officer’s estate.
9.    Nonassignability of Benefits. The payments under this Policy or the right to receive future payments under this Policy may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for payments becomes bankrupt, the payments under the Policy of the person affected may be terminated by the Administrator who, in his or her sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that he or she deems appropriate.
10.    Nonguarantee of Employment. Officers covered by the Policy are at-will employees, and nothing contained in this Policy shall be construed as a contract of employment between the Officer and the Corporation (or, where applicable, a subsidiary or affiliate of the Corporation), or as a right of the Officer to continued employment, or to remain as an Officer, or as a limitation on the right of the Corporation (or a subsidiary or affiliate of the Corporation) to discharge Officer at any time, with or without cause.
11.    Benefits Unfunded and Unsecured. The payments under this Policy are unfunded, and the interest under this Policy of any Officer and such Officer’s right to receive payments under this Policy shall be an unsecured claim against the general assets of the Corporation.
12.    Applicable Law. All questions pertaining to the construction, validity, and effect of the Policy shall be determined in accordance with the laws of the United States and, to the extent not preempted by such laws, by the laws of the state of California.
13.    Arbitration. With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Policy, Officer’s employment with the Corporation (or with the employing subsidiary), the termination thereof or any claims for benefits shall be resolved exclusively by final and binding arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making their determination, the arbitrators shall be limited to accepting the position of the Officer or the position of the Corporation, as the case may be. The only claims not covered by this Section 13 are claims for benefits under workers’ compensation or unemployment insurance laws; such claims will be resolved under those laws. The place of arbitration shall be San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The prevailing party in any dispute or controversy covered by this Section 13, or
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with respect to any request for specific performance, injunctive or other equitable relief, shall be entitled to recover, in addition to any other available remedies specified in this Policy, all litigation expenses and costs, including any arbitrator or administrative or filing fees and reasonable attorneys’ fees. Such expenses, costs and fees, if payable to Officer, shall be paid within 60 days after they are incurred. Both the Officer and the Corporation specifically waive any right to a jury trial on any dispute or controversy covered by this Section 13. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction.
14.    Reimbursements and In-Kind Benefits. Notwithstanding any other provision of this Policy, all reimbursements and in-kind benefits provided under this Policy shall be made or provided in accordance with the requirements of Code Section 409A, including, where applicable, the requirement that (i) the amount of expenses eligible for reimbursement and the provision of benefits in kind during a calendar year shall not affect the expenses eligible for reimbursement or the provision of in-kind benefits in any other calendar year; (ii) the reimbursement for an eligible expense will be made on or before the last day of the calendar year following the calendar year in which the expense is incurred (or by such earlier time set forth in this Policy); (iii) the right to reimbursement or right to in-kind benefit is not subject to liquidation or exchange for another benefit; and (iv) each reimbursement payment or provision of in-kind benefit shall be one of a series of separate payments (and each shall be construed as a separate identified payment) for purposes of Code Section 409A.
15.    Separate Payments. Each payment and benefit under this Policy shall be a “separate payment” for purposes of Code Section 409A.
16.    Claims and Appeals Procedure. Any claims for benefits under the Plan made by a participant, beneficiary or other person shall be made and administered in accordance with the following procedures.
(a)    Compliance with Regulations. It is intended that the claims procedure of the Plan be administered in accordance with the claims procedure regulations of the U.S. Department of Labor set forth in 29 C.F.R. Section 2560.503-1.
(b)    Initial Claims.
(1)    Submission of Initial Claims by a Claimant. Claims for benefits under the Plan made by a participant, beneficiary or other person covered or claiming they are entitled to benefits from the Plan (a “Claimant”) (or by an authorized representative of any Claimant) must be submitted in writing to the Director, Benefits, or if the title for the position ever changes, the individual employed in Benefits with direct management responsibility over the Plan (whether a Manager or some other title) (such individual, the “Initial Claim Reviewer”), care of Benefits.
(2)    Authorized Representative. The Plan Administrator may establish and enforce reasonable procedures for determining whether any individual or entity has been authorized to act on behalf of a Claimant.
(3)    Processing of Approved Claims. Approved claims will be processed and, if applicable, the Plan Administrator will issue instructions authorizing payments as approved.
(4)    Notification of Denied Claims. If a claim is denied in whole or in part by the Initial Claim Reviewer in its discretion, the Initial Claim Reviewer shall notify the Claimant of the decision by written or electronic notice, in a manner calculated to be understood by the Claimant. The notice shall set forth:
a.    The specific reasons for the denial of the claim;
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b.    A reference to specific provisions of the Plan on which the denial is based;
c.    A description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
d.    An explanation of the Plan’s claims review procedure for the denied or partially denied claim and any applicable time limits, and a statement that the Claimant has a right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review.
Such notification shall be given within 90 days after the claim is received by the Initial Claim Reviewer (or within 180 days, if special circumstances require an extension of time for processing the claim and provided that written notice of such extension and circumstances and the date a decision is expected is given to the Claimant within the initial 90-day period). A claim is considered approved only if its approval is communicated in writing to a Claimant.
(c)    Appeals of Denied Claims.
(1)    Right to Appeal. Upon denial of a claim in whole or in part, a Claimant or his or her duly authorized representative shall have the right to submit a written request to the Employee Benefit Appeals Committee, as such term is defined the Pacific Gas and Electric Company Retirement Plan Part I, as amended and restated from time to time (the “Employee Benefit Appeals Committee”) for a full and fair review of the denied claim. A request for review of a claim must be submitted within 60 days of receipt by the Claimant of written notice of the denial of the claim. If the Claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the Claimant is precluded from reasserting it. Also, if the Claimant is not provided a notice of denial of an initial claim as set forth in Section 16(b), the Claimant may submit a written request for review to the Employee Benefit Appeals Committee.
(2)    Access to Documents and Records. The Claimant or the Claimant’s representative shall have, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits.
(3)    Right to Submit Additional Information. The Claimant may submit written comments, documents, records and other information relating to the claim for benefits.
(4)    Scope of the Review. The Employee Benefit Appeals Committee review process shall include all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
(5)    Preclusion for Materials Not Submitted. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(6)    Decision by the Employee Benefit Appeals Committee. The decision by the Employee Benefit Appeals Committee on review shall be in written or electronic form, in a manner calculated to be understood by the Claimant. If the claim is denied on review, the notice shall set forth:
a.    The specific reasons for the denial of the appeal of the claim;
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b.    A reference to specific provisions of the Plan on which the denial is based;
c.    A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and;
d.    A statement describing any voluntary appeal procedures offered by the Plan (if any) and the Claimant’s right to obtain the information about such procedures, and a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA.
The Employee Benefit Appeals Committee will advise the Claimant of the results of the review within 60 days after receipt of the written request for review (or within 120 days if special circumstances require an extension of time for processing the request, and if notice of such extension and circumstances, including the date a decision is expected to be made, is given to such Claimant within the initial 60-day period).
(d)    Authority of Initial Claim Reviewer and Employee Benefit Appeals Committee and Deference to their Decisions. To the extent of the responsibility to review initial benefit claims (with respect to the Initial Claim Reviewer) or to review appeals of the denial of benefit claims (with respect to the Employee Benefit Appeals Committee), the Initial Claim Reviewer and the Employee Benefit Appeals Committee, shall have the discretionary authority to interpret and apply the provisions of the Plan and such decisions shall be afforded the maximum deference permitted by law. Benefits will be paid only if the Initial Claim Reviewer (with respect to initial benefit claims) or the Employee Benefit Appeals Committee (with respect to appeals of the denial of benefit claims) decides in its discretion that the Claimant is entitled to them. The decisions of the Employee Benefit Appeals Committee shall be final and binding on the Claimant.
(e)    Exhaustion of Claims Procedure Required in All Cases. A participant, beneficiary or other person asserting a claim, alleging a violation of or seeking any remedy under any provision of ERISA or other applicable law that relates in any manner to the Plan is considered a Claimant and is subject to the claims procedures described in this Section 16.
A participant, beneficiary or other person made subject to the claims procedures in this Section 16 must follow and exhaust the applicable claims procedures described in this Section 16 with respect to any claim, alleged violation, or sought remedy before taking action in any other forum regarding a claim for benefits under the Plan or alleging a violation of, or seeking any remedy under, any provision of ERISA or other applicable law.
A Claimant and any representative of a Claimant may not bring an action in any other forum later than the earliest of (1) one year from the date of completion of the Plan’s claims appeal process set forth in this Section 16, (2) one year from the latest date on which an appeal is permitted to be filed under this claims and appeals process after the denial of an initial claim (i.e., within 60 days of receipt of an initial claim denial notification), and (3) two years from the date a Claimant knew or should have known that a claim existed. The foregoing in no way serves as a waiver of the exhaustion requirement set forth in the preceding paragraph.
Any action described in this Section 16(e) must be filed in the Federal District Court for the Northern District of California.
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APPENDIX A
PARTICIPATING EMPLOYERS

PG&E Corporation
Pacific Gas and Electric Company
PG&E Corporation Support Services, Inc.
PG&E Corporation Support Services II, Inc.







EXHIBIT 31.1



CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Patricia K. Poppe, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 of PG&E Corporation;

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

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

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

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

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

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

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

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

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

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

Date: October 25, 2023/s/ PATRICIA K. POPPE
 Patricia K. Poppe
 Chief Executive Officer



CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Carolyn J. Burke, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 of PG&E Corporation;

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

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

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

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

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

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

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

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

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

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

Date: October 25, 2023/s/ CAROLYN J. BURKE
 Carolyn J. Burke
 Executive Vice President and Chief Financial Officer


EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Sumeet Singh, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: October 25, 2023 /s/ SUMEET SINGH
 Sumeet Singh
 Executive Vice President, Operations and Chief Operating Officer





CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Marlene M. Santos, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: October 25, 2023/s/ MARLENE M. SANTOS
 
Marlene M. Santos
 Executive Vice President and Chief Customer Officer










CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Jason M. Glickman, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: October 25, 2023/s/ JASON M. GLICKMAN
 Jason M. Glickman
 Executive Vice President, Engineering, Planning and Strategy







CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Stephanie N. Williams, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 of Pacific Gas and Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: October 25, 2023/s/ STEPHANIE N. WILLIAMS
 Stephanie N. Williams
 Vice President, Chief Financial Officer and Controller
EXHIBIT 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended September 30, 2023 (“Form 10-Q”), I, Patricia K. Poppe, Chief Executive Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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


 /s/ PATRICIA K. POPPE
 
Patricia K. Poppe
 Chief Executive Officer

October 25, 2023




CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended September 30, 2023 (“Form 10-Q”), I, Carolyn J. Burke, Executive Vice President and Chief Financial Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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


 /s/ CAROLYN J. BURKE
 
Carolyn J. Burke
 Executive Vice President and Chief Financial Officer

October 25, 2023
EXHIBIT 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended September 30, 2023 (“Form 10-Q”), I, Sumeet Singh, Executive Vice President, Operations and Chief Operating Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:


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

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

 /s/ SUMEET SINGH
 
Sumeet Singh
                               Executive Vice President, Operations and Chief Operating Officer

October 25, 2023




























CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended September 30, 2023 (“Form 10-Q”), I, Marlene M. Santos, Executive Vice President and Chief Customer Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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


 /s/ MARLENE M. SANTOS
 
Marlene M. Santos
 
Executive Vice President and Chief Customer Officer

October 25, 2023





































CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended September 30, 2023 (“Form 10-Q”), I, Jason M. Glickman, Executive Vice President, Engineering, Planning and Strategy of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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


 /s/ JASON M. GLICKMAN
 
Jason M. Glickman
 
Executive Vice President, Engineering, Planning and Strategy

October 25, 2023































CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended September 30, 2023 (“Form 10-Q”), I, Stephanie N. Williams, Vice President, Chief Financial Officer and Controller of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

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

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


 /s/ STEPHANIE N. WILLIAMS
 Stephanie N. Williams
 Vice President, Chief Financial Officer and Controller

October 25, 2023