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

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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 (such as undergrounding). 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’s wildfire mitigation efforts have also benefited in recent years from improved ignition response and situational awareness tools like weather stations and risk modeling. These initiatives have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned from utility-related ignitions. 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 September 30, 2024, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.2 billion, $1.875 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 September 30, 2024, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $525 million for the 2021 Dixie fire, and $86 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 September 30, 2024, the Utility has recorded a Wildfire Fund receivable of $875 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 September 30, 2024, the Utility has recorded receivables for regulatory recovery of $598 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 and Restated Articles of Incorporation, 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 (the “Amended Articles”) limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. 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 2,615,288,444 shares outstanding as of October 30, 2024, only 2,137,544,854 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 October 30, 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 nine months ended September 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 nine months ended September 30, 2024 and 2023:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2024		2023		2024		2023
Consolidated Total	$	576	$	348	$	1,828	$	1,323
PG&E Corporation	(39)		(69)		(126)		(193)
Utility	$	615	$	417	$	1,954	$	1,516

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

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Operating Revenues
Electric	$	4,538	$	4,507	$	13,048	$	12,478
Natural gas	1,403		1,381		4,740		4,909
Total operating revenues	5,941		5,888		17,788		17,387
Operating Expenses
Cost of electricity	835		846		1,919		2,040
Cost of natural gas	89		158		822		1,348
Operating and maintenance	2,678		3,136		8,062		8,241
SB 901 securitization charges, net	33		346		33		908
Wildfire-related claims, net of recoveries	74		(32)		70		(35)
Wildfire Fund expense	139		219		295		453
Depreciation, amortization, and decommissioning	1,059		811		3,134		2,885
Total operating expenses	4,907		5,484		14,335		15,840
Operating Income	1,034		404		3,453		1,547
Interest income	153		151		486		401
Interest expense	(721)		(594)		(2,125)		(1,667)
Other income, net	82		62		240		210
Income Before Income Taxes	548		23		2,054		491
Income tax provision (benefit)	(70)		(397)		90		(1,035)
Net Income	618		420		1,964		1,526
Preferred stock dividend requirement	3		3		10		10
Income Available for Common Stock	$	615	$	417	$	1,954	$	1,516

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $53 million, or 1%, in the three months ended September 30, 2024, compared to the same period in 2023. These increases were primarily due to:

approximately $735 million in increased base revenues authorized in the 2023 GRC in the three months ended September 30, 2024, as compared to the same period in 2023;
an increase of approximately $245 million in revenues as authorized through the FERC formula rate in the three months ended September 30, 2024, as compared to 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 September 30, 2024, with no comparable revenues in the same period in 2023; and
approximately $85 million related to the 2021 NDCTP final decision that ordered the Utility to issue a refund of the Non-Qualified Trust to customers in the three months ended September 30, 2023 with no comparable refund in the same period in 2024.

Partially offset by:

approximately $740 million in revenues authorized in the final 2021 WMCE decision (see “2021 WMCE Application” below) in the three months ended September 30, 2023, with no comparable revenues in the same period in 2024;
approximately $270 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended September 30, 2023, with no comparable revenues in the same period in 2024; and
a decrease of approximately $140 million in revenues to recover the costs associated with lower allowance for doubtful accounts under-collections from residential customers in the three months ended September 30, 2024, as compared to the same period in 2023. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

The Utility’s electric and natural gas operating revenues increased by $401 million, or 2%, in the nine months ended September 30, 2024, compared to the same period in 2023. These increases were primarily due to:

approximately $2.2 billion in increased base revenues authorized in the 2023 GRC in the nine months ended September 30, 2024, as compared to the same period in 2023;
an increase of approximately $270 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the nine months ended September 30, 2024, as compared to the same period in 2023;
an increase of approximately $260 million in revenues as authorized through the FERC formula rate in the nine months ended September 30, 2024, as compared to the same period in 2023;
approximately $260 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the nine months ended September 30, 2024, with no comparable revenues in the same period in 2023; and
approximately $85 million related to the 2021 NDCTP final decision that ordered the Utility to issue a refund of the Non-Qualified Trust to customers in the nine months ended September 30, 2023 with no comparable refund in the same period in 2024.

Partially offset by:

approximately $740 million in revenues authorized in the final 2021 WMCE decision (see “2021 WMCE Application” below) in the nine months ended September 30, 2023, with no comparable revenues in the same period in 2024;
approximately $585 million in revenues authorized in the final 2020 WMCE decision in the nine months ended September 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 $120 million and the cost of natural gas, which decreased by approximately $530 million in the nine months ended September 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 $295 million in revenues to recover the costs associated with the Risk Transfer Balancing Account (“RTBA”) in the nine months ended September 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 $280 million in revenues to recover the costs associated with lower allowance for doubtful accounts under-collections from residential customers in the the nine months ended September 30, 2024, as compared to the same period in 2023. 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 September 30,				Nine Months Ended September 30,
(in millions)	2024		2023		2024		2023
Cost of purchased power, net	$	754	$	752	$	1,700	$	1,518
Fuel used in generation facilities	81		94		219		522
Total cost of electricity	$	835	$	846	$	1,919	$	2,040

The Cost of electricity decreased by $11 million, or 1% in the three months ended September 30, 2024, compared to the same period in 2023. These decreases were primarily the result of lower natural gas market prices included as fuel costs.

The Cost of electricity decreased by $121 million, or 6% in the nine months ended September 30, 2024, 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 September 30,				Nine Months Ended September 30,
(in millions)	2024		2023		2024		2023
Cost of natural gas sold	$	48	$	116	$	691	$	1,226
Transportation cost of natural gas sold	41		42		131		122
Total cost of natural gas	$	89	$	158	$	822	$	1,348

The Cost of natural gas decreased by $69 million, or 44%, in the three months ended September 30, 2024, 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 $526 million, or 39%, in the nine months ended September 30, 2024, compared to the same period in 2023. These decreases were primarily the result of lower natural gas procurement costs, partially offset by less favorable 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 decreased by $458 million, or 15%, in the three months ended September 30, 2024, compared to the same period in 2023. These decreases were primarily due to:

approximately $720 million of previously deferred expenses authorized in the 2021 WMCE decision (see “2021 WMCE Application” below) in the three months ended September 30, 2023, with no comparable costs in the same period in 2024;
approximately $270 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the three months ended September 30, 2023, with no comparable costs in the same period in 2024;
a decrease of approximately $140 million in costs associated with lower allowance for doubtful accounts under-collections from residential customers in the three months ended September 30, 2024, as compared to the same period in 2023. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1; and
a decrease of approximately $40 million in insurance costs related to the Utility’s adoption of self-insurance in the three months ended September 30, 2024, as compared to the same period in 2023.

Partially offset by:

an increase of approximately $250 million in costs related to VMBA in the nine months ended September 30, 2024, as compared to the same period in 2023;
approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs and ordering the Utility to record these as operating expense, resulting in an increase in operating expense in the three months ended September 30, 2024, with no comparable costs 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 September 30, 2024, with no comparable costs in the same period in 2023; and
approximately $110 million of previously deferred expenses as a result of the 2023 GRC in the three months ended September 30, 2024, with no comparable costs in the same period in 2023.

The Utility’s Operating and maintenance expenses decreased by $179 million, or 2%, in the nine months ended September 30, 2024, compared to the same period in 2023. These decreases were primarily due to:

approximately $720 million of previously deferred expenses authorized in the 2021 WMCE decision (see “2021 WMCE Application” below) in the nine months ended September 30, 2023, with no comparable costs in the same period in 2024;
approximately $420 million of previously deferred expenses authorized in the final 2020 WMCE decision in the nine months ended September 30, 2023, with no comparable costs in 2024;
a decrease of approximately $280 million in costs associated with lower allowance for doubtful accounts under-collections from residential customers in the nine months ended September 30, 2024, as compared to the same period in 2023. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1; and
a decrease of approximately $340 million in insurance costs related to the Utility’s adoption of self-insurance in the nine months ended September 30, 2024, as compared to the same period in 2023.

Partially offset by:

approximately $330 million of previously deferred expenses as a result of the 2023 GRC in the nine months ended September 30, 2024, with no comparable costs in 2023;
an increase of approximately $270 million of previously deferred expenses authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in the nine months ended September 30, 2024, as compared to the same period in 2023;
approximately $260 million in interim rate relief authorized in the WGSC proceeding (see “Wildfire and Gas Safety Costs Recovery Application” below) in the nine months ended September 30, 2024, with no comparable costs in the same period in 2023;
an increase of approximately $250 million in costs related to VMBA in the nine months ended September 30, 2024, as compared to the same period in 2023;
approximately $210 million in costs related to a FERC order denying the capitalization of certain vegetation management costs, ordering the Utility to reclassify these costs to operating expense in the nine months ended September 30, 2024, with no comparable costs in the same period in 2023; and
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 nine months ended September 30, 2024, with no comparable costs in the same period in 2023. For more information, see “Regulatory Matters” below.

SB 901 Securitization Charges, Net

The Utility’s SB 901 securitization charges, net decreased by $313 million, or 90%, and $875 million, or 96%, in the three and nine months ended September 30, 2024, compared to the same periods in 2023. In the three and nine months ended September 30, 2023, the Utility recorded charges of $346 million and $908 million, respectively, representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock as well as amortization of Wildfire Fund contributions under AB 1054, as compared to charges of $33 million in the three and nine months ended September 30, 2024 related to amortization of Wildfire Fund contributions under AB 1054. For more information, see Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Wildfire Fund under AB 1054” in Note 10 below.

Wildfire-Related Claims, Net of Recoveries

The Utility’s Wildfire-related claims, net of recoveries increased by $106 million, or 331%, and $105 million, or 300%, in the three and nine months ended September 30, 2024, compared to the same periods in 2023. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire offset by probable recoveries through the Wildfire Fund and WEMA in the three and nine months ended September 30, 2023, as compared to pre-tax charges of $275 million related to the 2021 Dixie fire offset by probable recoveries through the Wildfire Fund and $75 million related to the 2019 Kincade fire in the three and nine months ended September 30, 2024.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense decreased by $80 million, or 37%, and $158 million, or 35%, in the three and nine months ended September 30, 2024, compared to the same periods in 2023. These decreases were primarily due to less accelerated amortization of the Wildfire Fund asset and an 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 $248 million, or 31%, and $249 million, or 9%, in the three and nine months ended September 30, 2024, compared to the same periods in 2023. These increases were primarily due to the growth in plant balance from capital additions, an increase in depreciation expense for costs awaiting regulatory decisions, and an increase in decommissioning expense due to the reversal of approximately $175 million in accrued nuclear decommissioning expense as a result of the 2021 NDCTP final decision in the three and nine months ended September 30, 2023, with no comparable reversals in the same periods in 2024.

Interest Income

There was no material change to Interest income in the three months ended September 30, 2024.

The Utility’s Interest income increased by $85 million, or 21%, in the nine months ended September 30, 2024, compared to the same period in 2023. This increase was primarily due to higher interest rates earned on regulatory balancing accounts.

Interest Expense

The Utility’s Interest expense increased by $127 million, or 21%, and $458 million, or 27%, in the three and nine months ended September 30, 2024, compared to the same periods in 2023. These increases were primarily due to an increase in long term debt and short-term debt, reversals of interest expense cost deferrals recorded in prior periods, and higher interest rates paid on regulatory balancing accounts.

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 $327 million, or 82%, and $1.1 billion, or 109%, in the three and nine months ended September 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 pre-tax income in the three and nine months ended September 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 September 30,				Nine Months Ended September 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)	(1.8)	%	(447.9)	%	2.0	%	(55.5)	%
Effect of regulatory treatment of fixed asset differences (2)	(26.2)	%	(417.4)	%	(17.7)	%	(59.8)	%
Tax credits	(0.7)	%	(63.9)	%	(0.6)	%	(4.0)	%
Fire Victim Trust (3)	—	%	(953.1)	%	—	%	(125.4)	%
Other, net	(5.1)	%	151.6	%	(0.3)	%	13.2	%
Effective tax rate	(12.8)	%	(1,709.7)	%	4.4	%	(210.5)	%

(1) Includes the effect of state flow-through ratemaking treatment.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. These amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Cuts and Jobs Act of 2017.

(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 September 30, 2024, PG&E Corporation and the Utility had access to approximately $5.2 billion of total liquidity comprised of $712 million of the Utility’s Cash and cash equivalents, which includes $305 million related to PERS, $183 million of PG&E Corporation’s Cash and cash equivalents and $4.3 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, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash and restricted cash equivalents 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 September 30, 2024, PG&E Corporation and the Utility had Cash and cash equivalents of $183 million and $712 million, respectively.

As of September 30, 2024, the Utility had contributed $768 million to PERS, its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance. As of September 2024, $305 million was classified as Cash and cash equivalents, $8 million was classified as Restricted cash and restricted cash equivalents due to minimum capital and surplus requirements, and $449 million was classified as Other current assets due to investments in short-term securities. 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

Utility

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.

On September 5, 2024, the Utility completed the sale of (i) $1.0 billion aggregate principal amount of Floating Rate First Mortgage Bonds due 2025 and (ii) $750 million aggregate principal amount of 5.900% First Mortgage Bonds due 2054. The Utility used the net proceeds for the repayment of a portion of borrowings outstanding under its existing bridge term loan credit agreement.

AB 1054 Securitization

On August 1, 2024, PG&E Recovery Funding LLC issued approximately $1.42 billion of Series 2024-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $300 million with an interest rate of 4.838% due June 1, 2035, (2) approximately $373 million with an interest rate of 5.231% due June 1, 2042, and (3) approximately $746 million with an interest rate of 5.529% due June 1, 2051. The $1.41 billion net proceeds were used by the Utility to reimburse itself for previously incurred fire risk mitigation capital expenditures through the repayment of a portion of loans outstanding under the Utility Revolving Credit Agreement.

For more information, see “AB 1054 Securitization” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

PG&E Corporation

On September 11, 2024, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055. These notes will initially bear interest at the rate of 7.375% per annum, and beginning March 15, 2030 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.883% (but not below 7.375%). PG&E Corporation used the net proceeds for general corporate purposes, including to prepay in full, all loans outstanding under its existing term loan agreement in an aggregate principal amount equal to $500 million.

Facilities and Term Loans

As of September 30, 2024, PG&E Corporation and the Utility had $500 million and $3.8 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 prepayments of $100 million on April 15, 2024 and $1.75 billion on September 5, 2024, the total aggregate principal amount of term loans outstanding under such credit agreement is $250 million.

On July 25, 2024, the Utility amended its existing revolving credit agreement to extend the maturity date for commitments representing $4.196 billion in the aggregate from June 22, 2028 to June 22, 2029 (subject to a one-year extension at the option of the Utility). The remaining $204 million of commitments will mature on June 22, 2028.

PG&E Corporation

On July 25, 2024, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date from June 22, 2026 to June 22, 2027 (subject to a one-year extension at the option of PG&E Corporation), and (ii) remove the cash coverage ratio covenant.

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 each of February 13 and May 16, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on May 15 and August 15, 2024, respectively, to holders of record as of April 30 and July 31, 2024. On September 19, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on November 15, 2024, to holders of record as of October 31, 2024.

On each of February 13, May 16, and September 19, 2024, the Board of Directors of the Utility declared common stock dividends of $450 million, $500 million, and $500 million, which were paid to PG&E Corporation on March 25, June 3, and September 20, 2024, respectively.

PG&E Corporation

On each of February 13, May 16, and September 19, 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, July 15, and October 15, 2024, to holders of record as of March 28, June 28 and September 30, 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 nine months ended September 30, 2024 and 2023.

The Utility’s cash flows were as follows:


	Nine Months Ended September 30,
(in millions)	2024		2023
Net cash provided by operating activities	$	6,272	$	4,530
Net cash used in investing activities	(8,219)		(6,710)
Net cash provided by financing activities	2,257		1,991
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	$	310	$	(189)

Operating Activities

Net cash provided by operating activities increased by $1.7 billion, or 38%, during the nine months ended September 30, 2024, as compared to the same period in 2023. The increases were primarily due to:

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 outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and
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 nine months ended September 30, 2024, compared to September 30, 2023.


(in millions)	Nine Months Ended September 30,
Cash used in investing activities - 2023	$	(6,710)
Capital expenditures	(440)
Net purchases related to customer credit trust investments	(641)
Purchases of self-insurance investments	(449)
Other investing activities	21
Net increase in cash used in investing activities	(1,509)
Cash used in investing activities - 2024	$	(8,219)

Net cash used in investing activities increased by $1.5 billion, or 22%, during the nine months ended September 30, 2024, as compared to the same period in 2023. The increases were primarily due to a $641 million increase in net purchases of customer credit trust investments, net of proceeds from sales, and a $449 million increase in purchases of self-insurance investments in 2024. In addition, capital expenditures increased by $440 million in 2024 compared to 2023 primarily due to an increase in capital work related to electric distribution, transmission and substation projects.

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, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust investments, and self-insurance 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 $10.8 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 nine months ended September 30, 2024, compared to September 30, 2023.


(in millions)	Nine Months Ended September 30,
Cash provided by financing activities - 2023	$	1,991
Net borrowings under credit facilities	(340)
Repayments under term loan credit facilities	(1,850)
Issuance of long-term debt	(1,691)
Issuance of short-term debt	999
Proceeds from issuance of Series 2024-A senior secured recovery bonds	1,409
Proceeds related to DWR loans	980
Other financing activities	759
Net increase in cash provided by financing activities	266
Cash provided by financing activities - 2024	$	2,257

Net cash provided by financing activities increased by $266 million, or 13%, during the nine months ended September 30, 2024, as compared to the same period in 2023. The increases were primarily due to:

$1.4 billion in proceeds related to the issuance of Series 2024-A senior secured recovery bonds, with no similar transaction in 2023;
$999 million in proceeds related to issuance of short-term debt, with no similar transaction in 2023; and
$980 million in proceeds related to the DWR loan in 2024, with no similar transaction in 2023.

Partially offset by:

a $1.9 billion increase in repayments under term loan credit facilities; and
a $1.7 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, 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 September 30, 2024 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

On October 17, 2024, the CPUC issued a final decision in the Utility’s 2023 Cost of Capital proceeding that changed the cost of capital adjustment mechanism and lowered the Utility’s ROE from 10.70% to 10.28% effective January 1, 2025.
On September 12, 2024, the CPUC issued a final decision on interim rate recovery in the Utility’s 2023 WMCE that grants the Utility interim rate relief of $944 million, plus interest, subject to refund.
On August 29, 2024, the OEIS issued a draft decision approving the Utility’s 2025 WMP update.
On August 22, 2024, the FERC issued an order approving the Utility’s TO18 transmission rate case settlement as reasonable and in the public interest.

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 proceedings. 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 later 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 September 30, 2024, the Utility had recorded an aggregate amount of approximately $4.1 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $2.9 billion was accounted for as long term as of September 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 nine months ended September 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. Decision authorizing $944 million of interim rate relief adopted September 2024.
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 September 26, 2024, the CPUC extended the deadline to resolve the remaining issues in the proceeding to December 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. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund. 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.

On September 16, 2024, the CPUC issued a final decision on interim rate recovery that grants the Utility interim rate relief of $944 million, plus interest, subject to refund, to be recovered over at least 17 months starting October 1, 2024. The remaining $914 million, plus interest, would be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

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 administrative law judge (“ALJ”) has adopted a schedule that would result in a proposed decision 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 September 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 2 issued July 2024 sets a cumulative expenditure cap at $2.26 billion for the period of 2024 to 2026.
2023 Cost of Capital, Phase 2	Maintain cost of capital adjustment mechanism	Final decision issued October 2024, changing the cost of capital adjustment mechanism and reduced the Utility’s ROE from 10.70% to 10.28% effective January 1, 2025.
TO18, TO19, and TO20	See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1	Settlement approved by the FERC August 2024.
TO21	Revenue requirement of $2.78 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 and Energization Timelines OIR

On September 15, 2023, the Utility served opening testimony proposing to 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. On July 16, 2024, the CPUC issued a final decision approving a memorandum account with interim rate relief, subject to annual caps and reasonableness review in the 2027 GRC application. The overall expenditure cap was set at $2.26 billion for the period of 2024 to 2026. The decision also provides the Utility the ability to request revisions to the 2025 and 2026 cap amounts under certain conditions. On October 4, 2024, the Utility filed a motion to increase the 2025 and 2026 cap amounts by an aggregate $3.1 billion, which reflects approximately $300 million originally included in 2024, for a net increase of $2.8 billion.

On October 18, 2024, the assigned commissioner issued an amended scoping memo providing for a final decision in spring 2025.

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. On October 18, 2024, the CPUC issued an order denying rehearing.

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.

On October 17, 2024, the CPUC issued a final decision which reduced the Utility’s ROE effective January 1, 2025 from 10.70% to 10.28% in conjunction with a change to the cost of capital adjustment mechanism (discussed below). As part of the updated ROE, the Utility will be allowed to update the cost of long-term debt effective January 1, 2025. Other policy changes to the cost of capital mechanism, including the Utility’s request for an upward adjustment to the interest rate applicable to the Utility’s balancing and memorandum accounts, were not adopted.

The Utility will file the next cost of capital application on March 20, 2025 for test year 2026.

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.

On October 17, 2024, the CPUC issued a final decision which changed the cost of capital adjustment mechanism such that the Utility’s ROE will be adjusted by 20% as opposed to one-half of the difference between the average Moody’s Baa utility bond rates and the benchmark rates.

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 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 denying the 0.5% ROE adder for participation in the CAISO, which results in a forecast transmission revenue requirement of $2.78 billion. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s denial of the 0.5% ROE adder for participation in the CAISO. 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 June 12, 2024, the FERC issued an order denying the Utility’s request for rehearing. On June 18, 2024, the Utility and California IOUs filed an appeal of the FERC’s order denying the Utility’s request for rehearing. The utilities’ joint opening brief was filed on September 11, 2024.

Other Regulatory Proceedings

2020-2022 Wildfire Mitigation Plans

On February 26, 2023, the OEIS issued its final Annual Report on Compliance (“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 denying in part the change order request.

The Utility submitted an updated 2025 WMP on April 2, 2024, as directed by the OEIS. On August 29, 2024, the OEIS issued a draft approval of the Utility’s 2025 WMP update.

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 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. Since December 22, 2022, on an ongoing basis, the Utility submits updates to the CPUC regarding 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. On October 11, 2024, the Utility updated its testimony and net recovery request to reflect updated market conditions closer to the time when rates go into effect. The resulting updated net recovery request is approximately $761 million. The request represents approximately $1.36 billion of forecasted expenditures and collectible revenues, offset by forecasted market revenues of approximately $624 million, and incorporating certain fees for the final net recovery amount.

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. On August 1, 2024, PG&E Recovery Funding LLC issued approximately $1.42 billion of Series 2024-A senior secured recovery bonds.

See “Liquidity and Financial Resources” above.

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.

The OEIS issued draft guidelines on May 8, 2024 and revised guidelines on September 10, 2024. 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 nine months ended September 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 nine months ended September 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.

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