PG&E Corp [PCG] Filings

10-Q 1 pcg-20240630.htm 10-Q pcg-20240630

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

FORM

10-Q

(Mark One)

☒

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

For the quarterly period ended

June 30, 2024

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

For the transition period from ___________ to __________

Commission
File
Number

Exact Name of
Registrant
as Specified
in its Charter

State or Other
Jurisdiction of
Incorporation

IRS Employer
Identification
Number

1-12609

PG&E Corporation

California

94-3234914

1-2348

Pacific Gas and Electric Company

California

94-0742640

PG&E Corporation

Pacific Gas and Electric Company

300 Lakeside Drive

Oakland,

California

94612

Oakland,

California

94612

Address of principal executive offices, including zip code

PG&E Corporation

Pacific Gas and Electric Company

415

973-1000

415

973-7000

Registrant’s telephone number, including area code


Securities registered pursuant to Section 12(b) of the Act:

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

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:

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Yes

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Pacific Gas and Electric Company:

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Yes

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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

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Pacific Gas and Electric Company:

☒

Yes

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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:

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Large accelerated filer

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Accelerated filer

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Non-accelerated filer

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Smaller reporting company

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Emerging growth company

Pacific Gas and Electric Company:

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Large accelerated filer

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Accelerated filer

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Non-accelerated filer

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Smaller reporting company

☐

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

PG&E Corporation:

☐

Pacific Gas and Electric Company:

☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

PG&E Corporation:

☐

Yes

☒

Pacific Gas and Electric Company:

☐

Yes

☒

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

PG&E Corporation:

☒

Yes

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Pacific Gas and Electric Company:

☒

Yes

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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 July 17, 2024:

PG&E Corporation:

2,615,204,752*

Pacific Gas and Electric Company:

264,374,809

*Includes 477,743,590 shares of common stock held by Pacific Gas and Electric Company.

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2024

TABLE OF CONTENTS


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


EXHIBITS						Part II, Item 6
SIGNATURES

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

GLOSSARY

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


2023 Form 10-K			PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2023
Form 10-Q			PG&E Corporation’s and the Utility’s joint Quarterly Report on Form 10-Q for the period ended June 30, 2024
AB			Assembly Bill
ALJ			administrative law judge
Amended Articles			Amended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020, and for PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022
ARC			Annual Report on Compliance
ASU			accounting standard update issued by the Financial Accounting Standards Board
Bankruptcy Court			the United States Bankruptcy Court for the Northern District of California
CAISO			California Independent System Operator Corporation
Cal Fire			California Department of Forestry and Fire Protection
CEMA			Catastrophic Event Memorandum Account
Chapter 11			Chapter 11 of Title 11 of the United States Code
Chapter 11 Cases			the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
CPPMA			COVID-19 Pandemic Protections Memorandum Account
CPUC			California Public Utilities Commission
CRR			congestion revenue rights
Diablo Canyon			Diablo Canyon nuclear power plant
District Court			United States District Court for the Northern District of California
DOE			United States Department of Energy
DTSC			California Department of Toxic Substances Control
DWR			California Department of Water Resources
EMANI			European Mutual Association for Nuclear Insurance
Emergence Date			July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOEP			Enhanced Oversight and Enforcement Process
EPS			earnings per common share
Exchange Act			Securities Exchange Act of 1934, as amended
FERC			Federal Energy Regulatory Commission
Fire Victim Trust			The trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be, funded
First Mortgage Bonds			bonds issued pursuant to the Indenture of Mortgage, dated as of June 19, 2020, between the Utility and The Bank of New York Mellon Trust Company, N.A., as amended and supplemented
FRMMA			Fire Risk Mitigation Memorandum Account
GAAP			United States Generally Accepted Accounting Principles
GO			general order
GRC			general rate case
HSMA			Hazardous Substance Memorandum Account
IOUs			investor-owned utility(ies)
IRC			Internal Revenue Code of 1986, as amended
Lakeside Building			300 Lakeside Drive, Oakland, California, 94612
MD&A			Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part I, Item 2, of this Form 10-Q
MGP			manufactured gas plants


NAV			net asset value
NEIL			Nuclear Electric Insurance Limited
NRC			Nuclear Regulatory Commission
OEIS			Office of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
Pacific Generation			Pacific Generation LLC, a subsidiary of the Utility
PCWA			Placer County Water Agency
PERA			Public Employees Retirement Association of New Mexico
Plan			PG&E Corporation and the Utility, Knighthead Capital Management, LLC, and Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
PSPS			Public Safety Power Shutoff
Receivables Securitization Program			The accounts receivable securitization program entered into by the Utility on October 5, 2020, providing for the sale of a portion of the Utility's accounts receivable and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions
ROE			return on equity
ROU asset			right-of-use asset
RUBA			Residential Uncollectibles Balancing Account
SB			Senate Bill
SEC			United States Securities and Exchange Commission
SED			Safety and Enforcement Division of the CPUC
SFGO			The Utility’s former San Francisco General Office headquarters complex
SPV			PG&E AR Facility, LLC
TCJA			Tax Cuts and Jobs Act of 2017
TO			transmission owner
USFS			United States Forest Service
Utility			Pacific Gas and Electric Company
Utility Revolving Credit Agreement			Credit Agreement, dated as of July 1, 2020, as amended, by and among the Utility, the several banks and other financial institutions or entities party thereto from time to time and Citibank, N.A., as Administrative Agent and Designated Agent
VIE(s)			variable interest entity(ies)
VMBA			Vegetation Management Balancing Account
WEMA			Wildfire Expense Memorandum Account
WGSC			Wildfire and Gas Safety Costs
Wildfire Fund			statewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
WMBA			Wildfire Mitigation Balancing Account
WMCE			Wildfire Mitigation and Catastrophic Events
WMP			Wildfire Mitigation Plan
WMPMA			Wildfire Mitigation Plan Memorandum Account

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 cost savings; 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 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; 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 the OEIS that the Utility has not complied with its WMP;

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

•significant changes to the electric power and natural 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 self-generation, customer departures to community choice aggregators, direct access providers, and government-owned utilities, and legislative mandates to reduce the use of natural gas; 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 Utility’s ability to attract or retain specialty personnel;

•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; 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;

•the outcome of current and future self-reports, investigations or other enforcement actions, agency compliance reports, 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, the Wildfire-Related Non-Bankruptcy Securities Claims, and other third-party claims, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings, 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 use securitization to finance the recovery of the remaining $1.385 billion of fire risk mitigation capital expenditures that were 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 high 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 the Utility’s ability 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 this Form 10-Q and the 2023 Form 10-K and a detailed discussion of these matters contained in Item 7. MD&A in the 2023 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.

PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “Wildfire and Safety Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident 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 websites 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 Item 1A. Risk Factors in the 2023 Form 10-K, as supplemented below and the section of this quarterly report entitled “Forward-Looking Statements.”

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

PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility. Accordingly, PG&E Corporation’s cash flow, ability to pay dividends on its common stock, and ability to meet its debt service obligations under its existing and future indebtedness largely depend upon the earnings and cash flows of the Utility and the distribution of these earnings and cash flows to PG&E Corporation. The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and is restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in financing agreements. See “Liquidity and Financial Resources” in Item 7. MD&A in the 2023 Form 10-K. The Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to meet its obligations to employees and creditors, and to pay preferred stock dividends, before it can distribute cash to PG&E Corporation. In particular, the CPUC requires PG&E Corporation’s and the Utility’s Boards of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC also regulates the Utility’s capital structure. Dividend payments on PG&E Corporation’s common stock are also subject to the discretion of PG&E Corporation’s Board of Directors. See Note 6 of the Notes to the Condensed Consolidated Financial Statements included in Item 1.

The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or make other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to pay common stock dividends or meet other obligations.

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 2023 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 Enhanced Powerline Safety Settings (“EPSS”), PSPS, vegetation management, asset inspections, and system hardening. In particular, in 2023, the Utility introduced or expanded its use of several measures including downed conductor detection, partial voltage force outs, and transmission operational controls. The Utility is also focused on undergrounding more lines each year while using economies of scale to make undergrounding more cost efficient. These initiatives have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.

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

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it continually reviews and has identified instances of noncompliance. The Utility intends to update the CPUC and the 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 may be 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 June 30, 2024, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.125 billion, $1.6 billion, and $100 million for claims in connection with the 2019 Kincade 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.

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.

As of June 30, 2024, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $525 million for the 2021 Dixie fire, and $83 million for the 2022 Mosquito fire. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have exceeded potential amounts recoverable under applicable insurance policies.

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 June 30, 2024, 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.

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 June 30, 2024, the Utility has recorded receivables for regulatory recovery of $587 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). The CPUC also authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers, 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. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. 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.

•PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing 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 achieving operating cost savings. The Utility plans to achieve such savings by improving the planning and execution of its work through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to minimize financing costs by identifying and executing on opportunities to efficiently finance the business, which depends on capital market conditions.

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors in this Form 10-Q and the 2023 Form 10-K and “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $32.9 billion and a California net operating loss carryforward of approximately $32.6 billion as of December 31, 2023.

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. Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore 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. For example, although PG&E Corporation had 2,615,204,752 shares outstanding as of July 17, 2024, only 2,137,461,162 shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of July 17, 2024 was 3.88% of PG&E Corporation’s outstanding 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.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and six months ended June 30, 2024 and 2023. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of income (loss) attributable to common shareholders for the three and six months ended June 30, 2024 and 2023:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Consolidated Total	$	520	$	406	$	1,252	$	975
PG&E Corporation	(41)		(70)		(87)		(124)
Utility	$	561	$	476	$	1,339	$	1,099

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 six months ended June 30, 2024 and 2023. 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 net income.


	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Operating Revenues
Electric	$	4,458	$	3,852	$	8,510	$	7,971
Natural gas	1,528		1,438		3,337		3,528
Total operating revenues	5,986		5,290		11,847		11,499
Operating Expenses
Cost of electricity	763		672		1,084		1,194
Cost of natural gas	204		274		733		1,190
Operating and maintenance	2,753		2,431		5,384		5,105
SB 901 securitization charges, net	—		289		—		562
Wildfire-related claims, net of recoveries	(3)		(1)		(4)		(3)
Wildfire Fund expense	78		117		156		234
Depreciation, amortization, and decommissioning	1,053		997		2,075		2,074
Total operating expenses	4,848		4,779		9,428		10,356
Operating Income	1,138		511		2,419		1,143
Interest income	199		140		333		250
Interest expense	(750)		(553)		(1,404)		(1,073)
Other income, net	79		64		158		148
Income Before Income Taxes	666		162		1,506		468
Income tax provision (benefit)	101		(318)		160		(638)
Net Income	565		480		1,346		1,106
Preferred stock dividend requirement	4		4		7		7
Income Available for Common Stock	$	561	$	476	$	1,339	$	1,099

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $696 million, or 13%, in the three months ended June 30, 2024, compared to the same period in 2023. These increases were primarily due to:

•approximately $650 million in increased base revenues authorized in the 2023 GRC in the three months ended June 30, 2024, as compared to the same period in 2023;

•approximately $275 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended June 30, 2024, with no comparable revenues in the same period in 2023;

•approximately $130 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the three months ended June 30, 2024, with no comparable revenues in the same period in 2023; and

•an increase in revenues to recover the cost of electricity procurement, which increased by approximately $90 million in the three months ended June 30, 2024, as compared to the same period in 2023. These costs are passed through to customers and do not impact net income. See “Cost of Electricity” below.

Partially offset by:

•a decrease of approximately $180 million in revenues to recover the costs associated with the Risk Transfer Balancing Account (“RTBA”) in the three months ended June 30, 2024, as compared to the same period in 2023. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K;

•a decrease of approximately $80 million in revenues to recover the costs associated with the RUBA in the three months ended June 30, 2024, as compared to the same period in 2023. These revenues and associated costs are passed through to customers and do not impact net income. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1; and

•a decrease in revenues to recover the cost of natural gas, which decreased by approximately $70 million in the three months ended June 30, 2024, as compared to the same period in 2023. These costs are passed through to customers and do not impact net income. See “Cost of Natural Gas” below.

The Utility’s electric and natural gas operating revenues increased by $348 million, or 3%, in the six months ended June 30, 2024, compared to the same period in 2023. These increases were primarily due to:

•approximately $1.3 billion in increased base revenues authorized in the 2023 GRC in the six months ended June 30, 2024, as compared to the same period in 2023;

•approximately $550 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the six months ended June 30, 2024, with no comparable revenues in the same period in 2023; and

•approximately $130 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the six months ended June 30, 2024, with no comparable revenues in the same period in 2023.

Partially offset by:

•approximately $585 million in revenues authorized in the final 2020 WMCE decision in the six months ended June 30, 2023, with no comparable revenues in the same period in 2024;

•a decrease in revenues to recover the cost of electricity procurement, which decreased by approximately $110 million and the cost of natural gas, which decreased by approximately $460 million in the six months ended June 30, 2024, as compared to the same period in 2023. These costs are passed through to customers and do not impact net income. See “Cost of Electricity” and “Cost of Natural Gas” below;

•a decrease of approximately $260 million in revenues to recover the costs associated with the RTBA in the six months ended June 30, 2024, as compared to the same period in 2023. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K; and

•a decrease of approximately $135 million in revenues to recover the costs associated with the RUBA in the six months ended June 30, 2024, as compared to the same period in 2023. These revenues and associated costs are passed through to customers and do not impact net income. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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 energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly with third parties. The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Cost of purchased power, net	$	715	$	626	$	946	$	765
Fuel used in generation facilities	48		46		138		429
Total cost of electricity	$	763	$	672	$	1,084	$	1,194

The Cost of electricity increased by $91 million, or 14% in the three months ended June 30, 2024, as compared to the same period in 2023. These increases were primarily the result of lower CAISO market sales revenues and increased nuclear fuel amortization costs, partially offset by lower natural gas market prices included as fuel costs.

The Cost of electricity decreased by $110 million, or 9% in the six months ended June 30, 2024, as compared to the same period in 2023. These decreases were primarily the result of lower natural gas market prices included as fuels costs, partially offset by lower CAISO market sales revenues.

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.


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Cost of natural gas sold	$	163	$	233	$	643	$	1,111
Transportation cost of natural gas sold	41		41		90		79
Total cost of natural gas	$	204	$	274	$	733	$	1,190

The Cost of natural gas decreased by $70 million, or 26%, in the three months ended June 30, 2024, as compared to the same period in 2023. These decreases were primarily the result of lower natural gas procurement costs, due to lower natural gas market prices for the period.

The Cost of natural gas decreased by $457 million, or 38%, in the six months ended June 30, 2024, as compared to the same period in 2023. These decreases were primarily the result of lower natural gas procurement costs, partially offset by unfavorable price risk management results, both of which were due to lower natural gas market prices for the period.

Operating and Maintenance

The Utility’s Operating and maintenance expenses increased by $322 million, or 13%, in the three months ended June 30, 2024, compared to the same period in 2023. These increases were primarily due to:

•approximately $275 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended June 30, 2024, with no comparable costs in the same period in 2023;

•approximately $110 million of previously deferred expenses as a result of the 2023 GRC in the three months ended June 30, 2024, with no comparable costs in the same period in 2023;

•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in the three months ended June 30, 2024, with no comparable costs in the same period in 2023. For more information, see “Regulatory Matters” below; and

•increased labor and benefit costs in the three months ended June 30, 2024, as compared to the same period in 2023.

Partially offset by:

•a decrease of approximately $125 million in insurance costs related to the Utility’s adoption of self-insurance in the three months ended June 30, 2024, as compared to the same period in 2023;

•a decrease of approximately $80 million in costs associated with the RUBA in the three months ended June 30, 2024, as compared to the same period in 2023. These costs are passed through to customers and do not impact net income. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1;

•$50 million related to the civil stipulated judgement filed on May 31, 2023, by the Utility and the Shasta County District Attorney’s Office (“Shasta D.A.”) for the Shasta D.A. to dismiss with prejudice all criminal charges against the Utility in connection with the 2020 Zogg fire (the “Zogg Stipulation’), with no comparable costs in 2024; and

•increased operating cost efficiencies in the three months ended June 30, 2024.

The Utility’s Operating and maintenance expenses increased by $279 million, or 5%, in the six months ended June 30, 2024, compared to the same period in 2023. These increases were primarily due to:

•approximately $550 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the six months ended June 30, 2024, with no comparable costs in 2023;

•approximately $220 million of previously deferred expenses as a result of the 2023 GRC in the six months ended June 30, 2024, with no comparable costs in 2023;

•the write-off of approximately $60 million of costs as a result of the CPUC’s final decision denying the Pacific Generation application in the six months ended June 30, 2024, with no comparable costs in the same period in 2023. For more information, see “Regulatory Matters” below; and

•increased labor and benefit costs in the six months ended June 30, 2024, as compared to the same period in 2023.

Partially offset by:

•approximately $420 million of previously deferred expenses authorized in the final 2020 WMCE decision in the six months ended June 30, 2023, with no comparable costs in 2024;

•a decrease of approximately $300 million in insurance costs related to the Utility’s adoption of self-insurance in the six months ended June 30, 2024, as compared to the same period in 2023;

•a decrease of approximately $135 million in costs associated with the RUBA in the six months ended June 30, 2024, as compared to the same period in 2023. These costs are passed through to customers and do not impact net income. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1;

•the recognition of $50 million related to the Zogg Stipulation in the six months ended June 30, 2023, with no comparable costs in 2024; and

•increased operating cost efficiencies in the six months ended June 30, 2024.

SB 901 Securitization Charges, Net

The Utility’s SB 901 securitization charges, net decreased by $289 million, or 100%, and $562 million, or 100% in the three and six months ended June 30, 2024, compared to the same periods in 2023. In the three and six months ended June 30, 2023, the Utility recorded charges of $289 million and $562 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, with no comparable charges in 2024. For more information, see Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Wildfire-Related Claims, Net of Recoveries

There was no material change to Wildfire-related claims, net of recoveries for the periods presented.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense decreased by $39 million, or 33%, and $78 million, or 33%, in the three and six months ended June 30, 2024, compared to the same periods in 2023. This decrease was due to the increase in the estimated period of coverage of the Wildfire Fund from 15 to 20 years. For more information, see Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Depreciation, Amortization, and Decommissioning

The Utility's Depreciation, amortization and decommissioning expenses increased by $56 million, or 6%, and $1 million, or 0%, in the three and six months ended June 30, 2024, compared to the same periods in 2023. These increases were primarily due to the growth in plant balance from capital additions, partially offset by deferred depreciation expense for costs awaiting regulatory decisions, a decrease in decommissioning expense primarily as a result of the 2021 Nuclear Decommissioning Cost Triennial Proceeding final decision, and lower depreciation rates authorized in the 2023 GRC.

Interest Income

The Utility’s Interest income increased by $59 million, or 42%, and increased by $83 million, or 33%, in the three and six months ended June 30, 2024, compared to the same periods in 2023. These increases were primarily due to higher interest rates earned on regulatory balancing accounts.

Interest Expense

The Utility’s Interest expense increased by $197 million, or 36%, and increased by $331 million, or 31%, in the three and six months ended June 30, 2024 compared to the same periods in 2023. These increases were primarily due to an increase in long term debt with higher fixed interest rates and an increase in short-term debt with higher variable interest rates.

Other Income, Net

There was no material change to Other income, net of recoveries for the periods presented.

Income Tax Provision (Benefit)

The Utility’s Income tax provision increased by $419 million, or 132%, and $798 million, or 125%, in the three and six months ended June 30, 2024, compared to the same periods in 2023, primarily due to a decrease in the tax benefit recognized related to the Fire Victim Trust’s sale of PG&E Corporation common stock as well as higher pretax book income in the three and six months ended June 30, 2024, compared to the same periods in 2023.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	4.6	%	(53.6)	%	3.3	%	(36.0)	%
Effect of regulatory treatment of fixed asset differences (2)	(16.4)	%	(54.1)	%	(14.5)	%	(42.1)	%
Tax credits	(0.7)	%	(1.5)	%	(0.6)	%	(1.1)	%
Fire Victim Trust (3)	—	%	(124.5)	%	—	%	(84.4)	%
Other, net	6.6	%	17.8	%	1.4	%	6.4	%
Effective tax rate	15.2	%	(194.9)	%	10.6	%	(136.2)	%

(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 effect of the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023. For more information, see “Tax Matters” in Item 7. MD&A and Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short-term and in the long-term.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends 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. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation common stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.

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 June 30, 2024, PG&E Corporation and the Utility had access to approximately $3.3 billion of total liquidity comprised of approximately $1.1 billion of the Utility’s cash and cash equivalents, $255 million of PG&E Corporation’s cash and cash equivalents and $2.0 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Credit Ratings

Credit ratings 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. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s credit rating remains below investment grade, the Utility generally does not receive unsecured credit from its energy procurement counterparties and it may be required to increase its collateral postings if its credit rating is downgraded.

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.

As of June 30, 2024, the Utility had contributed $625 million to Pacific Energy Risk Solutions LLC, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance, of which approximately $8 million was classified as Restricted cash due to minimum capital and surplus requirements. See “Self-Insurance” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Financial Resources

Equity Financings

PG&E Corporation does not plan to issue any equity in 2024, except for employee compensation purposes. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, its share price, its earnings, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings.

Debt Financings

The Utility generally issues first mortgage bonds and secured debt to meet its long-term debt funding requirements.

On February 28, 2024, the Utility completed the sale of (i) $850 million aggregate principal amount of 5.550% First Mortgage Bonds due 2029, (ii) $1.1 billion aggregate principal amount of 5.800% First Mortgage Bonds due 2034 and (iii) $300 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The Utility used the net proceeds for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

AB 1054 Securitization

On July 24, 2024, the Utility and PG&E Recovery Funding LLC (the “Issuing Entity”) entered into an Underwriting Agreement with Goldman Sachs & Co. LLC, Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the underwriters party thereto with respect to the purchase and sale of $1.42 billion aggregate principal amount of senior secured recovery bonds, series 2024-A, to be issued by the Issuing Entity. The issuance is expected to close in August 2024.

Credit Facilities and Term Loans

As of June 30, 2024, PG&E Corporation and the Utility had $500 million and $1.5 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. 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 16, 2024, the Utility amended its existing term loan agreement to combine its $400 million 2-year tranche loan maturing April 19, 2024 and its $125 million 364-day tranche loan maturing April 16, 2024 into a single loan of $525 million maturing April 15, 2025. The 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 26, 2024, the Utility amended its existing receivables securitization program to, among other things, extend the scheduled termination date from June 9, 2025 to June 26, 2026.

On June 28, 2024, the Utility amended its existing bridge term loan credit agreement to, among other things, (i) extend the maturity date from August 15, 2024 to December 16, 2024, and (ii) modify the mandatory prepayment provision to require the Utility to prepay term loans outstanding under such credit agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance of debt securities or incurrence of any debt under any bank credit facilities (excluding AB 1054 securitizations and the Utility’s revolving credit agreement). After giving effect to a prepayment of $100 million on April 15, 2024, the total aggregate principal amount of term loans outstanding under such credit agreement is $2.0 billion.

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

Other Financings

The Utility is seeking financing through the Energy Infrastructure Reinvestment category of the DOE’s Clean Energy Financing Program to help fund California’s clean energy transition.

On February 20, 2024, the Utility entered into an agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. The costs related to such leased entitlements are and will continue to be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years. The transactions contemplated by the agreement are subject to FERC and CPUC approvals of pending or forthcoming filings.

Dividends

Utility

On February 13, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on May 15, 2024, to holders of record as of April 30, 2024. On May 16, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on August 15, 2024, to holders of record as of July 31, 2024.

On each of February 13 and May 16, 2024, the Board of Directors of the Utility declared common stock dividends of $450 million and $500 million, which were paid to PG&E Corporation on March 25 and June 3, 2024, respectively.

PG&E Corporation

On each of February 13 and May 16, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, each declaration totaling $21 million, which were paid on April 15 and July 15, 2024, to holders of record as of March 28 and June 28, 2024, respectively.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the six months ended June 30, 2024 and 2023.

The Utility’s cash flows were as follows:


	Six Months Ended June 30,
(in millions)	2024		2023
Net cash provided by operating activities	$	3,114	$	2,627
Net cash used in investing activities	(5,225)		(4,420)
Net cash provided by financing activities	2,671		1,772
Net change in cash, cash equivalents, and restricted cash	$	560	$	(21)

Operating Activities

Net cash provided by operating activities increased by $487 million, or 19%, during the six months ended June 30, 2024, as compared to the same period in 2023. The increases were primarily due to:

•a decrease in amounts paid for natural gas due to a decrease in natural gas commodity prices; and

•an increase in collections through rates as a result of the 2023 GRC final decision.

Partially offset by:

•an increase in climate credits issued to customers; and

•lower returns for collateral posted in 2024 due to a decrease in the volatility of gas prices.

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 and amortization that do not require the use of cash. The Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base and from cost recovery applications (see “Cost Recovery Proceedings” below for more information).

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 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;

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

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

•the timing and amount of electric commodity price volatility and differences between commodity costs and revenue collections.

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

Investing Activities

The following table summarizes changes in key components of the Utility’s investing cash flows for the six months ended June 30, 2024, compared to June 30, 2023.


(in millions)	Six Months Ended June 30,
Cash used in investing activities - 2023	$	(4,420)
Capital expenditures	(256)
Net purchases related to customer credit trust investments	(565)
Other investing activities	16
Net increase in cash used in investing activities	(805)
Cash used in investing activities - 2024	$	(5,225)

Net cash used in investing activities increased by $805 million, or 18%, during the six months ended June 30, 2024, as compared to the same period in 2023. The increase was primarily due to a $565 million increase in purchases of customer credit trust investments, net of proceeds from sales, in 2024. In addition, capital expenditures increased by $256 million in 2024 compared to 2023 primarily due to being able to complete more planned capital work in 2024 as result of fewer winter storm events.

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.

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 $10.4 billion of capital expenditures in 2024. Additionally, future cash flows used in investing activities could be impacted by the timing and amount of contributions to the self-insurance captive (see “Self-Insurance” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1) and to the customer credit trust, including $650 million to be contributed by March 2025 (see Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1).

Financing Activities

The following table summarizes changes in key components of the Utility’s financing cash flows for the six months ended June 30, 2024, compared to June 30, 2023.


(in millions)	Six Months Ended June 30,
Cash provided by financing activities - 2023	$	1,772
Net borrowings under credit facilities	2,730

Issuance of long-term debt	(2,431)



Proceeds related to DWR loans	600



Net increase in cash provided by financing activities	899
Cash provided by financing activities - 2024	$	2,671

Net cash provided by financing activities increased by $899 million, or 50%, during the six months ended June 30, 2024, as compared to the same period in 2023. The increases were primarily due to:

•a $2.7 billion increase in net borrowings under credit facilities; and

•$600 million in proceeds related to the DWR loan in 2024, with no similar transaction in 2023.

Partially offset by:

•a $2.4 billion decrease in proceeds related to issuance of long-term debt.

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 the Utility’s ability to procure financing from other sources, dividend payments, and equity contributions from PG&E Corporation.

LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 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 OEIS, 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. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing and outcome of the following proceedings.

During the three months ended June 30, 2024 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

•On July 16, 2024, the CPUC issued a final decision for Phase 2 of the GRC that set a cumulative expenditure cap at $2.26 billion for the period of 2024 to 2026 and provides the Utility the ability to revisit the 2025 and 2026 cap amounts under certain conditions.

•On May 31, 2024, the OEIS approved in part and rejected in part the 2024 WMP change order request, aligning the Utility’s planned wildfire investments with its GRC.

•On May 9, 2024, the CPUC issued a final decision denying the petition for modification in the 2023 Cost of Capital proceeding.

•On May 8, 2024, the CPUC issued a final decision denying the Pacific Generation application.

•On May 8, 2024, the OEIS issued draft guidelines for the 10-year distribution infrastructure undergrounding plan.

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. For instance, 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 on cost recovery. These accounts, which include the CEMA, WEMA, Fire Hazard Prevention Memorandum Account (“FHPMA”), FRMMA, WMPMA, VMBA, WMBA, and Microgrids Memorandum Account (“MGMA”) among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, and certain third-party wildfire claims. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than 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 of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of June 30, 2024, the Utility had recorded an aggregate amount of approximately $4.2 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $619 million was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of June 30, 2024. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

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” and “Wildfire and Gas Safety Costs Recovery Application” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the six months ended June 30, 2024 are summarized in the following table:

Proceeding

Request (1)

Status

2021 WMCE

Revenue requirement of approximately $1.47 billion

Partial settlement agreement to recover $721 million of revenue requirement approved August 2023.

2022 WMCE

Revenue requirement of approximately $1.29 billion

Filed December 2022. Decision authorizing $1.1 billion of interim rate relief adopted June 2023. Partial settlement filed December 2023.

2023 WMCE

Revenue requirement of approximately $1.86 billion

Application filed December 2023.

2023 WGSC

Revenue requirement of approximately $688 million

Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024.

(1) The revenue requirement request amounts do not include interest.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2021 WMCE Application

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

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The 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 August 10, 2023, the CPUC approved a settlement agreement among the Utility and intervenors pursuant to which the Utility began collecting a revenue requirement of $721 million over 24 months beginning September 1, 2023. The settlement agreement did not address the Utility’s revenue requirement of $592 million associated with costs recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

On June 10, 2024, the CPUC extended the deadline to resolve the remaining issues in the proceeding to September 30, 2024.

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. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. 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 December 22, 2023, the Utility filed an unopposed joint settlement with intervenors for an additional $70 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA and the WMBA. The settlement agreement did not address the Utility’s revenue requirement request of $916 million associated with costs recorded to the VMBA or the WMBA, for which cost recovery will be determined separately by the CPUC.

On May 20, 2024, the CPUC extended the statutory deadline to resolve the remaining issues in the proceeding to December 31, 2024.

2023 WMCE Application

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 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 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million, and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

In connection with the 2023 WMCE application, the Utility also requested interim rate relief of $1.46 billion to be recovered over 12 months beginning March 1, 2024. The remaining $399 million would be recovered after the CPUC issues a final decision. On January 29, 2024, the Utility filed a supplemental motion for interim rate relief based on an agreement with the Public Advocates Office of the CPUC. Under the supplemental motion, the Utility would recover $944 million over 17 months, at least $500 million of which would be recovered in 2024. Following the 17-month period, the Utility would recover the remaining $515 million amount up to $1.46 billion.

The CPUC’s procedural schedule indicates a final decision by the second quarter of 2025.

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 $688 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:


(in millions)	Recorded Costs
WMPMA	$	2,095
FRMMA	165
Gas storage balancing account	101
In line inspection memorandum account	92
Other	45
Total	$	2,498

In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024.

The ALJ has adopted a schedule that would result in a proposed decision (“PD”) on the wildfire mitigation costs in the first half of 2025 and a final decision on the gas safety and electric modernization costs by June 2025.

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. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS approves guidelines. See “SB 884 10-Year Distribution Undergrounding Program” below.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the three months ended June 30, 2024 are summarized in the following table:

Rate Case

Request

Status

2023 GRC

Phase 2: balancing account for additional energization costs

Final decision on Phase 1 issued November 2023. Final decision on Phase 2 issued July 2024 sets a cumulative expenditure cap at $2.26 billion for the period of 2024 to 2026.

2023 Cost of Capital

Increase ROE to 11% and cost of debt to 4.31%

Final decision issued December 2022, adopting a 10% ROE. Final decision denying the intervenor petition for modification issued May 2024. Request for rehearing filed June 2024.

Cost of Capital Adjustment Mechanism

Increase ROE to 10.7% and cost of debt to 4.66%

Approved December 2023.

TO18, TO19, and TO20

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

Settlement filed with the FERC May 2024.

TO21

Revenue requirement of $2.83 billion for 2024

Accepted December 2023, except as to CAISO adder. Appeal of FERC’s order denying request for rehearing filed June 2024.

2023 General Rate Case

Phase 1

On November 17, 2023, the CPUC issued a final decision on Phase 1, Tracks 1 and 2. For more information, see “Regulatory Matters” in the 2023 Form 10-K.

Phase 2

On September 15, 2023, the Utility served opening testimony proposing to establish a balancing account to record and recover energization costs incremental to the forecasts of the Utility’s Phase 1 2023 GRC. Energization activities include new business connections and capacity-related work to allow for the connections and reduce energization timelines. 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. On July 16, 2024, the CPUC issued a final decision that set the expenditure cap at $2.26 billion for the period of 2024 to 2026 and provides the Utility the ability to revisit the 2025 and 2026 cap amounts under certain conditions.

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. On December 14, 2023, certain intervenors filed a petition for modification requesting that the 2023 cost of capital decision be modified to, among other things, suspend application of the cost of capital adjustment mechanism pending further CPUC decision. On May 9, 2024, the CPUC issued a final decision denying the petition for modification. On June 17, 2024, intervenors filed an application for rehearing of the decision denying their petition for modification.

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 and any further changes to the cost of capital adjustment mechanism to a second phase of the proceeding. The assigned ALJ has set a schedule that would fully resolve the proceeding by October 31, 2024.

Cost of Capital Adjustment Mechanism

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%, triggering the adjustment mechanism for the rest of the cost of capital period.

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%.

On December 22, 2023, the CPUC approved the Utility’s advice letter. As a result, the Utility is authorized to collect a revenue requirement of $328 million, based on the 2023 GRC rate base, effective January 1, 2024. Starting on January 1, 2024, the Utility’s authorized ROE increased from 10.0% to 10.7%, its authorized cost of long-term debt increased from 4.31% to 4.66%, and the benchmark has been updated to 5.78%. On January 12, 2024, several intervenors submitted a request for the CPUC to review the December 22, 2023 approval of the advice letter. On July 11, 2024, the CPUC issued a resolution confirming the approval of the advice letter.

Transmission Owner Rate Cases

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 the transaction to lease entitlements associated with certain transmission assets (see “Liquidity and Financial Resources - Other Financings” above). The Utility made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 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 ROE 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. On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but rejecting the 0.5% ROE adder for participation in the CAISO. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s rejection of the 0.5% ROE adder. On February 29, 2024, the FERC issued a notice of denial of rehearing by operation of law. FERC’s denial indicated that substantive issues related to rehearing will be addressed in a future order. On April 22, 2024, the Utility filed an appeal of the FERC’s order in the Court of Appeals for the Ninth Circuit. On June 12, 2024, the FERC issued an order denying the Utility’s request for rehearing. On June 18, 2024, the Utility filed an appeal of the FERC’s order denying the Utility’s request for rehearing. The two appeals have been consolidated.

Other Regulatory Proceedings

2020-2022 Wildfire Mitigation Plans

On February 26, 2023, the OEIS issued its final ARC for the Utility’s 2020 WMP. In the final ARC, the OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets, but 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 the OEIS failed to utilize the compliance evaluation criteria adopted by the CPUC. On June 11, 2024, the Utility and the OEIS entered into a settlement agreement, pursuant to which the Utility dismissed the writ and the OEIS agreed not to recommend that the CPUC pursue an enforcement action against the Utility or impose penalties. On July 10, 2024, enforcement staff of the CPUC determined that the Utility had remediated the defects in the ARC and that no further action was required.

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 December 29, 2023, the OEIS issued a final decision approving the Utility’s 2023-2025 WMP. On February 15, 2024, the CPUC ratified the OEIS’s approval. On January 8, 2024, the Utility filed a change order request to reflect spend amounts approved in the 2023 GRC final decision. On May 31, 2024, the OEIS issued a decision approving in part and rejecting in part the change order request.

The Utility submitted updates to the WMP for 2025 on April 2, 2024, as directed by the OEIS. The OEIS stated it will issue a decision on the 2025 WMP update by August 31, 2024.

Application with Pacific Generation 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, sought to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplated the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. On May 10, 2024, the CPUC issued a final decision denying the application.

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 2023 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, February 1, 2024, and July 1, 2024, the Utility submitted updates 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.

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.

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 (“LSEs”), and all customers of those LSEs would be responsible for the cost of extended operations.

The key steps to continued operations are NRC license renewal and approvals from California state agencies, including the CPUC, California Energy Resources Conservation and Development Commission, California State Lands Commission, California Coastal Commission, and other state agencies. In 2023, the Utility received approvals from the CPUC, California Energy Resources Conservation and Development Commission, California State Lands Commission, and California State Water Resources Control Board.

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On December 19, 2023, the NRC deemed the application sufficient, which allows continued operations at Diablo Canyon past the plant’s current licenses. The NRC’s schedule indicates that it will issue a final safety evaluation report and supplemental environmental impact statement by June 2025.

On March 29, 2024, the Utility submitted an application for net recovery through rates of approximately $418 million of costs associated with extended operations at Diablo Canyon for the period from 2023 through 2025. The request represents approximately $1.2 billion of forecasted expenditures and collectible revenues authorized by SB 846, offset by forecasted market revenues of $813 million, and incorporating certain fees for the final net recovery amount. The Utility expects to update its net recovery request in the fourth quarter of 2024, before the CPUC issues a final decision, to reflect updated market conditions and potential cost revisions.

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.

On August 10, 2023, the Utility filed an application with the CPUC seeking authorization for a third transaction to use securitization to finance the recovery of 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 second quarter of 2024. 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.

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.

On February 16, 2024, the CPUC issued a final decision approving the Utility’s application.

SB 884 10-Year Distribution Undergrounding Program

On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addresses the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs.

On December 13, 2023, the OEIS issued a request for comments as part of its ongoing process to develop guidelines for its program.

On May 8, 2024, the OEIS issued draft guidelines. The Utility anticipates that the OEIS will issue final guidelines in 2024.

The Utility expects to submit its undergrounding plan to the OEIS after final guidelines are issued before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this quarterly report, as well as Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K.

RISK MANAGEMENT ACTIVITIES

There have been no material changes to the Utility’s and PG&E Corporation’s risk management activities during the six months ended June 30, 2024. These activities are discussed in detail in Item 7 of the 2023 Form 10-K.

CRITICAL ACCOUNTING ESTIMATES

There have been no material changes to the Utility’s and PG&E Corporation’s critical accounting policies during the six months ended June 30, 2024. These accounting estimates and their key characteristics are discussed in detail in Item 7 of the 2023 Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)


	(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Operating Revenues
Electric	$	4,458	$	3,852	$	8,510	$	7,971
Natural gas	1,528		1,438		3,337		3,528
Total operating revenues	5,986		5,290		11,847		11,499
Operating Expenses
Cost of electricity	763		672		1,084		1,194
Cost of natural gas	204		274		733		1,190
Operating and maintenance	2,757		2,436		5,393		5,113
SB 901 securitization charges, net	—		289		—		562
Wildfire-related claims, net of recoveries	(3)		(1)		(4)		(3)
Wildfire Fund expense	78		117		156		234
Depreciation, amortization, and decommissioning	1,053		997		2,075		2,074
Total operating expenses	4,852		4,784		9,437		10,364
Operating Income	1,134		506		2,410		1,135
Interest income	202		143		339		255
Interest expense	(812)		(640)		(1,527)		(1,242)
Other income, net	82		66		158		151
Income Before Income Taxes	606		75		1,380		299
Income tax provision (benefit)	82		(335)		121		(683)
Net Income	524		410		1,259		982
Preferred stock dividend requirement of subsidiary	4		4		7		7
Income Available for Common Shareholders	$	520	$	406	$	1,252	$	975
Weighted Average Common Shares Outstanding, Basic	2,137		2,019		2,136		2,005
Weighted Average Common Shares Outstanding, Diluted	2,142		2,139		2,141		2,137
Net Income Per Common Share, Basic	$	0.24	$	0.20	$	0.59	$	0.49
Net Income Per Common Share, Diluted	$	0.24	$	0.19	$	0.58	$	0.46

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Net Income	$	524	$	410	$	1,259	$	982
Other Comprehensive Income

Net unrealized gains (losses) on available-for-sale securities (net of taxes of $0, $0, $1, and $2, respectively)	—		—		(1)		5
Total other comprehensive income (loss)	—		—		(1)		5
Comprehensive Income	524		410		1,258		987
Preferred stock dividend requirement of subsidiary	4		4		7		7
Comprehensive Income Available for Common Shareholders	$	520	$	406	$	1,251	$	980

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


	(Unaudited)
	Balance at
	June 30, 2024		December 31, 2023
ASSETS
Current Assets
Cash and cash equivalents	$	1,315	$	635
Restricted cash (includes $227 million and $282 million related to VIEs at respective dates)	237		297
Accounts receivable
Customers (net of allowance for doubtful accounts of $349 million and $445 million at respective dates) (includes $1.6 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $349 million and $445 million at respective dates)	1,982		2,048
Accrued unbilled revenue (includes $1.8 billion and $1.1 billion related to VIEs at respective dates)	2,038		1,254
Regulatory balancing accounts	6,698		5,660
Other	1,405		1,494
Regulatory assets	258		300
Inventories
Gas stored underground and fuel oil	56		65
Materials and supplies	767		805
Wildfire Fund asset	305		450
Other	1,678		1,375
Total current assets	16,739		14,383
Property, Plant, and Equipment
Electric	83,458		80,345
Gas	30,642		29,830
Construction work in progress	4,752		4,452
Financing lease ROU asset and other	786		787
Total property, plant, and equipment	119,638		115,414
Accumulated depreciation	(34,396)		(33,093)
Net property, plant, and equipment	85,242		82,321
Other Noncurrent Assets
Regulatory assets	16,230		17,189
Customer credit trust	505		233
Nuclear decommissioning trusts	3,740		3,574
Operating lease ROU asset	573		598
Wildfire Fund asset	4,289		4,297
Income taxes receivable	1		24
Other (includes noncurrent accounts receivable of $78 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $16 million and $0 at respective dates)	3,469		3,079
Total other noncurrent assets	28,807		28,994
TOTAL ASSETS	$	130,788	$	125,698

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)


	(Unaudited)
	Balance at
	June 30, 2024		December 31, 2023
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	4,972	$	3,971
Long-term debt, classified as current (includes $179 million and $176 million related to VIEs at respective dates)	1,578		1,376
Accounts payable
Trade creditors	2,149		2,309
Regulatory balancing accounts	2,151		1,669
Other	896		851
Operating lease liabilities	81		80
Financing lease liabilities	779		259
Interest payable (includes $67 million and $67 million related to VIEs at respective dates)	723		679
Wildfire-related claims	939		1,422
Other	4,275		4,698
Total current liabilities	18,543		17,314
Noncurrent Liabilities
Long-term debt (includes $10.4 billion and $10.5 billion related to VIEs at respective dates)	52,664		50,975
Regulatory liabilities	19,900		19,444
Pension and other postretirement benefits	464		476
Asset retirement obligations	5,564		5,512
Deferred income taxes	2,484		1,980
Operating lease liabilities	492		518
Financing lease liabilities	45		554
Other	4,127		3,633
Total noncurrent liabilities	85,740		83,092
Equity
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,137,460,355 and 2,133,597,758 shares outstanding at respective dates	30,379		30,374
Reinvested earnings	(4,112)		(5,321)
Accumulated other comprehensive loss	(14)		(13)
Total shareholders’ equity	26,253		25,040
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	26,505		25,292
TOTAL LIABILITIES AND EQUITY	$	130,788	$	125,698

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	(Unaudited)
	Six Months Ended June 30,
	2024		2023
Cash Flows from Operating Activities
Net income	$	1,259	$	982
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,075		2,074
Bad debt expense	135		293
Allowance for equity funds used during construction	(84)		(82)
Deferred income taxes and tax credits, net	485		(329)

Wildfire Fund expense	156		234

Other	(134)		41
Effect of changes in operating assets and liabilities:
Accounts receivable	(960)		1,589
Wildfire-related insurance receivable	196		347
Inventories	47		(46)
Accounts payable	419		145
Wildfire-related claims	(483)		(656)

Other current assets and liabilities	(692)		(220)
Regulatory assets, liabilities, and balancing accounts, net	734		(1,931)

Other noncurrent assets and liabilities	(181)		19
Net cash provided by operating activities	2,972		2,460
Cash Flows from Investing Activities

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10-Q	[2024-07-25]
10-Q	[2024-04-25]
10-K	[2024-02-22]
10-Q	[2023-10-26]
10-Q	[2023-07-27]
10-Q	[2023-05-04]
10-K	[2023-02-23]
10-Q	[2022-10-27]
10-Q	[2022-07-28]
10-Q	[2022-04-28]
10-K	[2022-02-10]
10-Q	[2021-11-01]
10-Q	[2021-07-29]
10-Q	[2021-04-29]
10-K	[2021-02-25]
10-Q	[2020-10-29]
10-Q	[2020-07-30]
10-Q	[2020-05-01]
10-K	[2020-02-18]
10-Q	[2019-11-07]
10-Q	[2019-08-09]
10-Q	[2019-05-02]
10-K	[2019-02-28]
10-Q	[2018-11-05]
10-Q	[2018-07-26]
10-Q	[2018-05-03]
10-K	[2018-02-09]
10-Q	[2017-11-02]
10-Q	[2017-07-27]
10-Q	[2017-05-02]
10-K	[2017-02-16]
10-Q	[2016-11-04]
10-Q	[2016-07-28]
10-Q	[2016-05-04]
10-K	[2016-02-18]
10-Q	[2015-10-28]
10-Q	[2015-07-29]
10-Q	[2015-04-29]
10-K	[2015-02-10]
10-Q	[2014-10-28]
10-Q	[2014-07-31]
10-Q	[2014-05-01]
10-K	[2014-02-11]
10-Q	[2013-10-30]
10-Q	[2013-07-31]
10-Q	[2013-05-02]
10-K	[2013-02-21]
10-Q	[2012-10-29]
10-Q	[2012-08-07]
10-Q	[2012-05-02]
10-K	[2012-02-16]

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