Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)


	(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Operating Revenues
Electric	$	4,414	$	4,458	$	8,549	$	8,510
Natural gas	1,484		1,528		3,332		3,337
Total operating revenues	5,898		5,986		11,881		11,847
Operating Expenses
Cost of electricity	599		763		998		1,084
Cost of natural gas	111		204		607		733
Operating and maintenance	2,860		2,757		5,506		5,393
Wildfire-related claims, net of recoveries	50		(3)		99		(4)
Wildfire Fund expense	109		78		185		156
Depreciation, amortization, and decommissioning	1,073		1,053		2,170		2,075
Total operating expenses	4,802		4,852		9,565		9,437
Operating Income	1,096		1,134		2,316		2,410
Interest income	181		202		298		339
Interest expense	(792)		(812)		(1,526)		(1,527)
Other income, net	84		82		154		158
Income Before Income Taxes	569		606		1,242		1,380
Income tax provision	20		82		59		121
Net Income	549		524		1,183		1,259
Preferred stock dividend requirement	28		4		55		7
Income Available for Common Shareholders	$	521	$	520	$	1,128	$	1,252
Weighted Average Common Shares Outstanding, Basic	2,198		2,137		2,196		2,136
Weighted Average Common Shares Outstanding, Diluted	2,203		2,142		2,201		2,141
Net Income Per Common Share, Basic	$	0.24	$	0.24	$	0.51	$	0.59
Net Income Per Common Share, Diluted	$	0.24	$	0.24	$	0.51	$	0.58

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,
	2025		2024		2025		2024
Net Income	$	549	$	524	$	1,183	$	1,259
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0 respectively)	—		—		1		—
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3, $0, $5 and $1 respectively)	8		—		14		(1)
Total other comprehensive income (loss)	8		—		15		(1)
Comprehensive Income	557		524		1,198		1,258
Preferred stock dividend requirement	28		4		55		7
Comprehensive Income Available for Common Shareholders	$	529	$	520	$	1,143	$	1,251

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


	(Unaudited)
	Balance at
	June 30, 2025		December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents	$	494	$	940
Restricted cash and restricted cash equivalents (includes $207 million and $263 million related to VIEs at respective dates)	221		273
Accounts receivable
Customers (net of allowance for doubtful accounts of $404 million and $418 million at respective dates) (includes $1.7 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $404 million and $418 million at respective dates)	2,025		2,220
Accrued unbilled revenue (includes $1.6 billion and $1.3 billion related to VIEs at respective dates)	1,862		1,487
Regulatory balancing accounts	5,657		7,227
Other (net of allowance for doubtful accounts of $89 million and $35 million at respective dates)	2,095		1,810
Regulatory assets	302		234
Inventories
Gas stored underground and fuel oil	73		52
Materials and supplies	713		768
Wildfire Fund asset	298		301
Wildfire self-insurance asset	969		905
Other	452		999
Total current assets	15,161		17,216
Property, Plant, and Equipment
Property, Plant, and Equipment	123,445		118,262
Construction work in progress	4,636		4,458
Financing lease ROU asset and other	7		814
Total property, plant, and equipment	128,088		123,534
Accumulated depreciation	(36,288)		(35,305)
Net property, plant, and equipment	91,800		88,229
Other Noncurrent Assets
Regulatory assets	15,853		15,561
Customer credit trust	935		377
Nuclear decommissioning trusts	4,022		3,833
Operating lease ROU asset	500		524
Wildfire Fund asset	3,891		4,070
Other (includes noncurrent accounts receivable of $72 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $17 million and $18 at respective dates)	4,222		3,850
Total other noncurrent assets	29,423		28,215
TOTAL ASSETS	$	136,384	$	133,660

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, 2025		December 31, 2024
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,524	$	1,523
Long-term debt, classified as current (includes $217 million and $222 million related to VIEs at respective dates)	3,643		2,146
Accounts payable
Trade creditors	2,663		2,748
Regulatory balancing accounts	2,516		3,169
Other	862		748
Operating lease liabilities	88		85
Financing lease liabilities	1		577
Interest payable (includes $65 million and $91 million related to VIEs at respective dates)	767		760
Wildfire-related claims	787		916
Other	3,334		3,658
Total current liabilities	16,185		16,330
Noncurrent Liabilities
Long-term debt (includes $10.2 billion and $10.1 billion related to VIEs at respective dates)	54,004		53,569
Regulatory liabilities	19,871		19,417
Pension and other postretirement benefits	824		808
Asset retirement obligations	5,499		5,444
Deferred income taxes	3,550		3,082
Operating lease liabilities	412		439
Financing lease liabilities	3		4
Other	4,598		4,166
Total noncurrent liabilities	88,761		86,929
Equity
Shareholders’ Equity
Mandatory convertible preferred stock	1,579		1,579
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,197,837,402 and 2,193,573,536 shares outstanding at respective dates	31,560		31,555
Reinvested earnings	(1,949)		(2,966)
Accumulated other comprehensive loss	(4)		(19)
Total shareholders’ equity	31,186		30,149
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	31,438		30,401
TOTAL LIABILITIES AND EQUITY	$	136,384	$	133,660

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,
	2025		2024
Cash Flows from Operating Activities
Net income	$	1,183	$	1,259
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,170		2,075
Bad debt expense	241		135
Allowance for equity funds used during construction	(97)		(84)
Deferred income taxes and tax credits, net	472		485
Wildfire Fund expense	185		156
Other	(29)		(134)
Effect of changes in operating assets and liabilities:
Accounts receivable	(562)		(960)
Wildfire-related insurance receivable	(133)		196
Inventories	34		47
Accounts payable	188		419
Wildfire-related claims	(129)		(483)
Other current assets and liabilities	(76)		(692)
Regulatory assets, liabilities, and balancing accounts, net	750		734
Other noncurrent assets and liabilities	(292)		(181)
Net cash provided by operating activities	3,905		2,972
Cash Flows from Investing Activities
Capital expenditures	(5,700)		(4,936)
Proceeds from sales and maturities of nuclear decommissioning trust investments	779		1,044
Purchases of nuclear decommissioning trust investments	(809)		(1,082)
Proceeds from sales and maturities of customer credit trust investments	196		174
Purchases of customer credit investments	(693)		(435)
Proceeds from self-insurance investments	186		—
Purchases of self-insurance investments	(237)		—
Other	10		10
Net cash used in investing activities	(6,268)		(5,225)
Cash Flows from Financing Activities
Borrowings under credit facilities	515		5,528
Repayments under credit facilities	(325)		(4,827)
Repayments under term loan	—		(100)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $27 and $9 at respective dates	2,973		2,259
Repayments of long-term debt	(1,050)		(450)
Repayment of AB 1054 recovery bonds	(48)		(23)
Repayment of SB 901 recovery bonds	(67)		(64)
Common stock dividends paid	(110)		(43)
Mandatory convertible preferred stock dividends paid	(48)		—
Proceeds from DWR loan	—		600
Other	25		(7)


Net cash provided by financing activities	1,865		2,873
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	(498)		620
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	1,213		932
Cash, cash equivalents, restricted cash, and restricted cash equivalents at June 30	$	715	$	1,552
Less: Restricted cash and restricted cash equivalents	(221)		(237)
Cash and cash equivalents at June 30	$	494	$	1,315


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,282)	$	(1,199)

Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,009	$	921
Operating lease liabilities arising from ROU assets	—		1

Financing lease liabilities arising from obtaining ROU assets	—		15

DWR loan forgiveness and performance-based disbursements	78		47
Common stock dividends declared but not yet paid	55		21
Mandatory convertible preferred stock dividends declared but not yet paid	24		—
Capital expenditures financed through current assets and non-current liabilities	592		—

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)


	Preferred Stock			Common Stock					Treasury Stock				Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity		Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
			Shares		Amount			Shares		Amount
Balance at December 31, 2024	$	1,579		2,193,573,536		$	31,555		—		$	—	$	(2,966)	$	(19)	$	30,149	$	252	$	30,401
Net income	—			—		—			—		—		634		—		634		—		634
Other comprehensive income	—			—		—			—		—		—		7		7		—		7
Common stock issued, net	—			4,111,477		(1)			—		—		—		—		(1)		—		(1)
Stock-based compensation amortization	—			—		(22)			—		—		—		—		(22)		—		(22)
Common stock dividends declared	—			—		—			—		—		(55)		—		(55)		—		(55)
Preferred stock dividend requirement	—			—		—			—		—		(27)		—		(27)		—		(27)
Balance at March 31, 2025	$	1,579		2,197,685,013		$	31,532		—		$	—	$	(2,414)	$	(12)	$	30,685	$	252	$	30,937
Net income	—			—		—			—		—		549		—		549		—		549
Other comprehensive income	—			—		—			—		—		—		8		8		—		8
Common stock issued, net	—			152,389		—			—		—		—		—		—		—		—
Stock-based compensation amortization	—			—		28			—		—		—		—		28		—		28
Common stock dividends declared	—			—		—			—		—		(56)		—		(56)		—		(56)
Preferred stock dividend requirement	—			—		—			—		—		(28)		—		(28)		—		(28)
Balance at June 30, 2025	$	1,579		2,197,837,402		$	31,560		—		$	—	$	(1,949)	$	(4)	$	31,186	$	252	$	31,438


	Common Stock			Treasury Stock			Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity		Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
	Shares	Amount		Shares	Amount
Balance at December 31, 2023	2,133,597,758	$	30,374	—	$	—	$	(5,321)	$	(13)	$	25,040	$	252	$	25,292
Net income	—	—		—	—		735		—		735		—		735
Other comprehensive loss	—	—		—	—		—		(1)		(1)		—		(1)
Common stock issued, net	3,558,470	—		—	—		—		—		—		—		—

Stock-based compensation amortization	—	(18)		—	—		—		—		(18)		—		(18)
Common stock dividends declared	—	—		—	—		(22)		—		(22)		—		(22)
Preferred stock dividend requirement	—	—		—	—		(3)		—		(3)		—		(3)
Balance at March 31, 2024	2,137,156,228	$	30,356	—	$	—	$	(4,611)	$	(14)	$	25,731	$	252	$	25,983
Net income	—	—		—	—		524		—		524		—		524
Common stock issued, net	304,127	—		—	—		—		—		—		—		—
Stock-based compensation amortization	—	23		—	—		—		—		23		—		23
Common stock dividends declared	—	—		—	—		(21)		—		(21)		—		(21)
Preferred stock dividend requirement	—	—		—	—		(4)		—		(4)		—		(4)
Balance at June 30, 2024	2,137,460,355	$	30,379	—	$	—	$	(4,112)	$	(14)	$	26,253	$	252	$	26,505

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions)


	(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Operating Revenues
Electric	$	4,414	$	4,458	$	8,549	$	8,510
Natural gas	1,484		1,528		3,332		3,337
Total operating revenues	5,898		5,986		11,881		11,847
Operating Expenses
Cost of electricity	599		763		998		1,084
Cost of natural gas	111		204		607		733
Operating and maintenance	2,854		2,753		5,492		5,384
Wildfire-related claims, net of recoveries	50		(3)		99		(4)
Wildfire Fund expense	109		78		185		156
Depreciation, amortization, and decommissioning	1,073		1,053		2,170		2,075
Total operating expenses	4,796		4,848		9,551		9,428
Operating Income	1,102		1,138		2,330		2,419
Interest income	179		199		293		333
Interest expense	(713)		(750)		(1,368)		(1,404)
Other income, net	83		79		154		158
Income Before Income Taxes	651		666		1,409		1,506
Income tax provision	39		101		102		160
Net Income	612		565		1,307		1,346
Preferred stock dividend requirement	4		4		7		7
Income Available for Common Stock	$	608	$	561	$	1,300	$	1,339

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Net Income	$	612	$	565	$	1,307	$	1,346
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0 respectively)	—		—		1		—
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3, $0, $5 and $1 respectively)	8		—		14		(1)
Total other comprehensive income (loss)	8		—		15		(1)
Comprehensive Income	$	620	$	565	$	1,322	$	1,345

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


	(Unaudited)
	Balance at
	June 30, 2025		December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents	$	236	$	705
Restricted cash and restricted cash equivalents (includes $207 million and $263 million related to VIEs at respective dates)	221		272
Accounts receivable
Customers (net of allowance for doubtful accounts of $404 million and $418 million at respective dates) (includes $1.7 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $404 million and $418 million at respective dates)	2,025		2,220
Accrued unbilled revenue (includes $1.6 billion and $1.3 billion related to VIEs at respective dates)	1,862		1,487
Regulatory balancing accounts	5,657		7,227
Other (net of allowance for doubtful accounts of $89 million and $35 million at respective dates)	2,097		1,810
Regulatory assets	302		234
Inventories
Gas stored underground and fuel oil	73		52
Materials and supplies	713		768
Wildfire Fund asset	298		301
Wildfire self-insurance asset	969		905
Other	449		998
Total current assets	14,902		16,979
Property, Plant, and Equipment
Property, Plant, and Equipment	123,445		118,262
Construction work in progress	4,635		4,458
Financing lease ROU asset and other	7		814
Total property, plant, and equipment	128,087		123,534
Accumulated depreciation	(36,287)		(35,304)
Net property, plant, and equipment	91,800		88,230
Other Noncurrent Assets
Regulatory assets	15,853		15,561
Customer credit trust	935		377
Nuclear decommissioning trusts	4,022		3,833
Operating lease ROU asset	496		519
Wildfire Fund asset	3,891		4,070
Other (includes noncurrent accounts receivable of $72 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $17 million and $18 at respective dates)	4,062		3,697
Total other noncurrent assets	29,259		28,057
TOTAL ASSETS	$	135,961	$	133,266

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)


	(Unaudited)
	Balance at
	June 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	1,524	$	1,523
Long-term debt, classified as current (includes $217 million and $222 million related to VIEs at respective dates)	3,643		2,146
Accounts payable
Trade creditors	2,661		2,745
Regulatory balancing accounts	2,516		3,169
Other	842		729
Operating lease liabilities	88		85
Financing lease liabilities	1		577
Interest payable (includes $65 million and $91 million related to VIEs at respective dates)	675		667
Wildfire-related claims	787		916
Other	3,056		3,331
Total current liabilities	15,793		15,888
Noncurrent Liabilities
Long-term debt (includes $10.2 billion and $10.1 billion related to VIEs at respective dates)	48,387		47,958
Regulatory liabilities	19,871		19,417
Pension and other postretirement benefits	757		741
Asset retirement obligations	5,499		5,444
Deferred income taxes	4,127		3,632
Operating lease liabilities	408		434
Financing lease liabilities	3		4
Other	4,626		4,198
Total noncurrent liabilities	83,678		81,828
Shareholders’ Equity
Preferred stock	258		258
Common stock, $5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates	1,322		1,322
Additional paid-in capital	36,705		35,930
Reinvested earnings	(1,790)		(1,940)
Accumulated other comprehensive loss	(5)		(20)
Total shareholders’ equity	36,490		35,550
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	135,961	$	133,266

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	(Unaudited)
	Six Months Ended June 30,
	2025		2024
Cash Flows from Operating Activities
Net income	$	1,307	$	1,346
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,170		2,075
Bad debt expense	241		135
Allowance for equity funds used during construction	(97)		(84)
Deferred income taxes and tax credits, net	498		529
Wildfire Fund expense	185		156
Other	(40)		(154)
Effect of changes in operating assets and liabilities:
Accounts receivable	(564)		(960)
Wildfire-related insurance receivable	(133)		196
Inventories	34		47
Accounts payable	188		408
Wildfire-related claims	(129)		(483)
Other current assets and liabilities	(35)		(652)
Regulatory assets, liabilities, and balancing accounts, net	749		734
Other noncurrent assets and liabilities	(287)		(179)
Net cash provided by operating activities	4,087		3,114
Cash Flows from Investing Activities
Capital expenditures	(5,700)		(4,936)
Proceeds from sales and maturities of nuclear decommissioning trust investments	779		1,044
Purchases of nuclear decommissioning trust investments	(809)		(1,082)
Proceeds from sales and maturities of customer credit trust investments	196		174
Purchases of customer credit investments	(693)		(435)
Proceeds from self-insurance investments	186		—
Purchases of self-insurance investments	(237)		—
Other	10		10
Net cash used in investing activities	(6,268)		(5,225)
Cash Flows from Financing Activities
Borrowings under credit facilities	515		5,528
Repayments under credit facilities	(325)		(4,827)
Repayments under term loan	—		(100)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $27 and $9 at respective dates	2,973		2,259
Repayments of long-term debt	(1,050)		(450)
Repayment of AB 1054 recovery bonds	(48)		(23)
Repayment of SB 901 recovery bonds	(67)		(64)
Preferred stock dividends paid	(7)		(7)
Common stock dividends paid	(1,150)		(950)
Equity contribution from PG&E Corporation	775		705


Proceeds from DWR loan	—		600
Other	45		—
Net cash provided by financing activities	1,661		2,671
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	(520)		560
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	977		736
Cash, cash equivalents, restricted cash, and restricted cash equivalents at June 30	$	457	$	1,296
Less: Restricted cash and restricted cash equivalents	(221)		(236)
Cash and cash equivalents at June 30	$	236	$	1,060


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,129)	$	(1,083)

Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,009	$	921
Operating lease liabilities arising from obtaining ROU assets	—		1
Financing lease liabilities arising from obtaining ROU assets	—		15

DWR loan forgiveness and performance-based disbursements	78		47
Capital expenditures financed through current assets and non-current liabilities	592		—

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)


	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2024	$	258	$	1,322	$	35,930	$	(1,940)	$	(20)	$	35,550
Net income	—		—		—		695		—		695
Other comprehensive income	—		—		—		—		7		7
Equity contribution	—		—		450		—		—		450
Common stock dividend	—		—		—		(575)		—		(575)
Preferred stock dividend requirement	—		—		—		(3)		—		(3)
Balance at March 31, 2025	$	258	$	1,322	$	36,380	$	(1,823)	$	(13)	$	36,124
Net income	—		—		—		612		—		612
Other comprehensive income	—		—		—		—		8		8
Equity contribution	—		—		325		—		—		325
Common stock dividend	—		—		—		(575)		—		(575)
Preferred stock dividend requirement	—		—		—		(4)		—		(4)
Balance at June 30, 2025	$	258	$	1,322	$	36,705	$	(1,790)	$	(5)	$	36,490


	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2023	$	258	$	1,322	$	30,570	$	(2,613)	$	(13)	$	29,524
Net income	—		—		—		781		—		781
Other comprehensive loss	—		—		—		—		(1)		(1)
Equity contribution	—		—		440		—		—		440
Common stock dividend	—		—		—		(450)		—		(450)
Preferred stock dividend requirement	—		—		—		(3)		—		(3)
Balance at March 31, 2024	$	258	$	1,322	$	31,010	$	(2,285)	$	(14)	$	30,291
Net income	—		—		—		565		—		565
Equity contribution	—		—		265		—		—		265
Common stock dividend	—		—		—		(500)		—		(500)
Preferred stock dividend requirement	—		—		—		(4)		—		(4)
Balance at June 30, 2024	$	258	$	1,322	$	31,275	$	(2,224)	$	(14)	$	30,617

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

Organization and Basis of Presentation

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

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information as of December 31, 2024 in the Condensed Consolidated Balance Sheets included in this Quarterly Report on Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2024 Form 10-K. This Quarterly Report on Form 10-Q should be read in conjunction with the 2024 Form 10-K.

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker (“CODM”) is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the CODM uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Condensed Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Condensed Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the CODM is not regularly provided with information that is considered to be significant under Accounting Standards Codification (“ASC”) 280, Segment Reporting. Except for publicly available information, the information regularly provided to the CODM consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.

Revenue Recognition

Revenue from Contracts with Customers

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

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

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

The following table presents the Utility’s revenues disaggregated by type of customer:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2025		2024		2025		2024
Electric
Revenue from contracts with customers
Residential	$	1,421	$	1,516	$	3,255	$	3,315
Commercial	1,613		1,655		3,119		3,160
Industrial	386		441		800		854
Agricultural	478		439		677		619
Public street and highway lighting	26		27		53		52
Other, net (1)	665		798		754		919
Total revenue from contracts with customers - electric	4,589		4,876		8,658		8,919
Regulatory balancing accounts (2)	(175)		(418)		(109)		(409)
Total electric operating revenue	$	4,414	$	4,458	$	8,549	$	8,510

Natural gas
Revenue from contracts with customers
Residential	$	430	$	213	$	2,139	$	1,730
Commercial	222		187		621		560
Transportation service only	456		424		1,002		899
Other, net (1)	(147)		(138)		(267)		(202)
Total revenue from contracts with customers - gas	961		686		3,495		2,987
Regulatory balancing accounts (2)	523		842		(163)		350
Total natural gas operating revenue	1,484		1,528		3,332		3,337
Total operating revenues	$	5,898	$	5,986	$	11,881	$	11,847

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent alternative revenues authorized to be billed or refunded to customers.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of June 30, 2025, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

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

Expected credit losses of $141 million and $241 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables during the three and six months ended June 30, 2025, respectively. For the three and six months ended June 30, 2024, expected credit losses were $65 million and $135 million, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of June 30, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $146 million and $90 million, respectively. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively. The RUBA current balancing account balance decreased from December 31, 2024 to June 30, 2025 primarily due to the annual electric and gas true-up, which allows the Utility to recover approximately $260 million in undercollections from residential customers in 2025.

Other Receivables and Available-For-Sale Debt Securities

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

As of June 30, 2025, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Government Assistance

The Utility participated in various government assistance programs during the three months ended June 30, 2025 and 2024. The Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of DCPP, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE’s Civil Nuclear Credit Program” below). Under the loan agreement, the DWR pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by DCPP, effective September 2, 2022. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. For more information about the DWR Loan Agreement, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2025		2024		2025		2024
Long-term debt:
Beginning Balance - DWR loan outstanding	$	812	$	296	$	886	$	98

Proceeds received	—		368		—		600

Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(10)		(17)		(18)		(39)
Operating and maintenance expense - Loan forgiveness and other adjustments	—		12		(57)		12

Other current liabilities:
Change in performance-based disbursements deferred	6		(8)		(3)		(20)

Long-term debt:
Ending Balance - DWR loan outstanding	$	808	$	651	$	808	$	651

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and the DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the DCPP operations. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility recognizes such funding as income and records a receivable related to government grants. During the three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected $60 million and $100 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the three and six months ended June 30, 2024, the Condensed Consolidated Statements of Income reflected $159 million and $299 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected $16 million and $57 million, respectively, as deductions to Cost of electricity, for income related to government grants for incurred fuel costs to support the extension of DCPP.

Variable Interest Entities

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

Consolidated VIEs

Receivables Securitization Program

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

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the six months ended June 30, 2025 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2025 and December 31, 2024, the SPV had net accounts receivable of $3.3 billion and $3.2 billion, respectively, and outstanding borrowings of $190 million and $0 million, respectively, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

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

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the six months ended June 30, 2025 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, November 30, 2022, and August 1, 2024, PG&E Recovery Funding LLC issued $860 million, $983 million, and $1.42 billion of senior secured recovery bonds, respectively. As of June 30, 2025 and December 31, 2024, PG&E Recovery Funding LLC had outstanding borrowings of $3.1 billion and $3.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets.

SB 901 Securitization

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

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the six months ended June 30, 2025 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022 and July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion and $3.9 billion of senior secured recovery bonds, respectively. As of June 30, 2025 and December 31, 2024, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.1 billion and $7.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets. For more information, see Note 5 below.

Non-Consolidated VIEs

Power Purchase Agreement**s

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of June 30, 2025, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of June 30, 2025, it did not consolidate any of them.

Contributions to the Wildfire Fund Established Pursuant to AB 1054

AB 1054 did not specify a period of coverage for the Wildfire Fund, and so the accounting treatment is subject to significant judgments and estimates. PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below.

In estimating the life of the fund, PG&E Corporation and the Utility use a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. PG&E Corporation’s and the Utility’s initial estimated life of the fund was 15 years. In the first quarter of 2024, a re-evaluation resulted in the estimated life increasing from 15 to 20 years.

The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund.

PG&E Corporation and the Utility have an established process to re-evaluate the estimated life of the fund whenever they obtain new significant fire-loss data. PG&E Corporation and the Utility consider significant fire-loss data to include Cal Fire’s annual release of the prior year’s fire-loss data, internally developed data about wildfires and wildfire conditions in their own service area, and other participating electric utilities’ public disclosures of probable and estimable wildfire-related losses in their service area. PG&E Corporation and the Utility are not able to independently verify other utilities’ estimates. During each re-evaluation, PG&E Corporation and the Utility update their assumptions and the dataset of historical fire-losses for wildfires caused by electrical equipment, as applicable. Based upon the outcome of the newly run Monte Carlo simulations, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. PG&E Corporation and the Utility apply adjustments to the estimated life of the fund on a prospective basis.

In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable, or when another participating electric utility discloses a Wildfire Fund receivable.

As of June 30, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $567 million in Other noncurrent liabilities, $298 million in Current assets - Wildfire Fund asset, and $3.9 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2025 and 2024, the Utility recorded amortization and accretion expense of $109 million and $78 million, respectively. During the six months ended June 30, 2025 and 2024, the Utility recorded amortization and accretion expense of $185 million and $156 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income.

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

Oakland Headquarters Purchase

On June 3, 2025, the Utility completed the purchase of the legal parcel that contains the Lakeside Building (the "Property"). The purchase price was $906 million, of which the Utility had prepaid a total of $400 million. At closing, the Utility assumed a $172 million noncurrent liability for a property assessment carried by the Property and paid an additional $349 million, which was adjusted for closing costs. The cash payment is included within the Capital expenditures line item in PG&E Corporation’s and Utility’s Condensed Consolidated Statements of Cash Flows, and the property assessment and prepayments are included in Supplemental disclosures of noncash investing and financing activities.

Pension and Other Post-Retirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2025 and 2024 were as follows:


	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2025		2024		2025		2024
Service cost for benefits earned (1)	$	106	$	99	$	10	$	11
Interest cost	252		229		19		18
Expected return on plan assets	(264)		(254)		(38)		(35)
Amortization of prior service (credit)	—		(1)		—		—
Amortization of net actuarial loss (gain)	1		1		(5)		(5)
Net periodic benefit cost	95		74		(14)		(11)
Regulatory account transfer (2)	(10)		(9)		—		—
Total	$	85	$	65	$	(14)	$	(11)

(1) A portion of service costs is capitalized pursuant to GAAP.

(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery or refund through rates in future periods.


	Pension Benefits				Other Benefits
	Six Months Ended June 30,
(in millions)	2025		2024		2025		2024
Service cost for benefits earned (1)	$	212	$	198	$	19	$	21
Interest cost	504		458		37		36
Expected return on plan assets	(527)		(507)		(75)		(70)
Amortization of prior service cost (credit)	(1)		(2)		1		1
Amortization of net actuarial loss (gain)	1		1		(11)		(11)
Net periodic benefit cost	189		148		(29)		(23)
Regulatory account transfer (2)	(20)		(19)		—		—
Total	$	169	$	129	$	(29)	$	(23)

(1) A portion of service costs is capitalized pursuant to GAAP.

(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

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

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

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

The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) consisted of the following:


	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
(in millions, net of income tax)	Three Months Ended June 30, 2025
Beginning balance	$	(35)	$	18	$	10	$	(7)
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0 and $3, respectively)	—		—		7		7
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively)	(1)		1		—		—
Amortization of net actuarial loss (gain) (net of taxes of $0, $2, and $0, respectively)	1		(4)		—		(3)
Regulatory account transfer (net of taxes of $0, $2, and $0, respectively)	1		3		—		4
Net current period other comprehensive gain	1		—		7		8
Ending balance	$	(34)	$	18	$	17	$	1

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.

(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Three Months Ended June 30, 2024
Beginning balance	$	(28)	$	18	$	1	$	(9)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively)	—		1		—		1
Amortization of net actuarial gain (net of taxes of $0, $2, and $0, respectively)	—		(4)		—		(4)
Regulatory account transfer (net of taxes of $0, $2, and $0, respectively)	—		3		—		3
Net current period other comprehensive loss	—		—		—		—
Ending balance	$	(28)	$	18	$	1	$	(9)


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Six Months Ended June 30, 2025
Beginning balance	$	(35)	$	18	$	3	$	(14)
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0, and $5, respectively)	—		—		14		14
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively)	(1)		1		—		—
Amortization of net actuarial loss (gain) (net of taxes of $0, $3, and $0, respectively)	1		(8)		—		(7)
Regulatory account transfer (net of taxes of $0, $3, and $0, respectively)	1		7		—		8
Net current period other comprehensive gain	1		—		14		15
Ending balance	$	(34)	$	18	$	17	$	1

(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Six Months Ended June 30, 2024
Beginning balance	$	(28)	$	18	$	2	$	(8)
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0, and $1, respectively)	—		—		(1)		(1)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $0, and $0, respectively)	(1)		1		—		—
Amortization of net actuarial gain (net of taxes of $0, $3, and $0, respectively)	—		(8)		—		(8)
Regulatory account transfer (net of taxes of $0, $3, and $0, respectively)	1		7		—		8
Net current period other comprehensive loss	—		—		(1)		(1)
Ending balance	$	(28)	$	18	$	1	$	(9)

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

Accounting Standards Issued But Not Yet Adopted

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09*, Income Taxes (Topic 740): Improvements to Income Tax Disclosures,* which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and disaggregation of income taxes paid by jurisdiction. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025. There is no significant impact on PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements and related disclosures. PG&E Corporation and the Utility will adopt this new ASU in its Form 10-K for the year ending December 31, 2025.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amends the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amends the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Noncurrent regulatory assets are comprised of the following:


	Balance at
(in millions)	June 30, 2025		December 31, 2024
Pension benefits	$	682	$	673
Environmental compliance costs	1,109		1,172
Price risk management	104		167
Catastrophic event memorandum account	762		742
Wildfire-related accounts	1,721		1,697
Deferred income taxes	5,242		4,771
Financing costs	209		216
SB 901 securitization	5,139		5,194
General rate case memorandum accounts	78		95
Other	807		834
Total noncurrent regulatory assets	$	15,853	$	15,561

Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:


	Balance at
(in millions)	June 30, 2025		December 31, 2024
Cost of removal obligations	$	9,265	$	8,943
Public purpose programs	1,192		1,112
Employee benefit plans	1,098		1,088
Transmission tower wireless licenses	282		306
SFGO sale	40		79
SB 901 securitization	6,145		6,295
Wildfire self-insurance	807		804
Other	1,042		790
Total noncurrent regulatory liabilities	$	19,871	$	19,417

Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:


	Balance at
(in millions)	June 30, 2025		December 31, 2024
Electric distribution	$	1,705	$	1,591
Electric transmission	113		117
Gas distribution and transmission	119		387
Energy procurement	1,285		1,066
Public purpose programs	207		162
Wildfire-related accounts	640		979
Insurance premium costs	—		38
Residential uncollectibles balancing accounts	146		260
Catastrophic event memorandum account	265		500
General rate case memorandum accounts	557		1,113
Other	620		1,014
Total regulatory balancing accounts receivable	$	5,657	$	7,227


	Balance at
(in millions)	June 30, 2025		December 31, 2024
Electric transmission	$	477	$	883
Gas distribution and transmission	61		72
Energy procurement	520		329
Public purpose programs	563		882
SFGO sale	42		93
Wildfire-related accounts	291		337
Nuclear decommissioning adjustment mechanism	10		23
Other	552		550
Total regulatory balancing accounts payable	$	2,516	$	3,169

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.

NOTE 4: DEBT

Credit Facilities and Term Loans

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of June 30, 2025:


(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2030	$	5,400	(1)	$	—	$	(388)	$	5,012
Utility Receivables Securitization Program (2)	June 2027	1,500		(3)	(190)		—		1,310		(3)
PG&E Corporation revolving credit facility	June 2028	650			—		—		650
Total credit facilities		$	7,550		$	(190)	$	(388)	$	6,972

(1) Includes a $2.0 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. 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 11, 2025, the Utility amended its existing $525 million term loan agreement to extend the maturity to April 10, 2026. 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 23, 2025, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 21, 2030, (ii) increase the aggregate commitments from $4.4 billion to $5.4 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2025, the Utility and the SPV amended the existing $1.5 billion Receivables Securitization Program to, among other things (i) extend the scheduled termination date from June 26, 2026 to June 25, 2027 and (ii) allow the Utility and the SPV to request an increase to the commitments by an additional aggregate amount up of to $250 million, subject to the satisfaction of certain terms and conditions.

PG&E Corporation

On June 23, 2025, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2028, (ii) increase the aggregate commitments from $500 million to $650 million and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

Long-Term Debt Issuances and Redemptions

Utility

On February 24, 2025, the Utility completed the sale of (i) $1.0 billion aggregate principal amount of 5.700% First Mortgage Bonds due 2035 and (ii) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for (i) the repayment of all of its $600 million aggregate principal amount of 3.500% First Mortgage Bonds due June 15, 2025, and (ii) the repayment of all of its $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 4, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028 and (ii) $850 million aggregate principal amount of 6.000% First Mortgage Bonds due 2035. The Utility expects to use the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount 3.15% First Mortgage Bonds due January 1, 2026.

Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% Convertible Senior Secured Notes due December 1, 2027 (the “Convertible Notes”).

As of both June 30, 2025 and December 31, 2024, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.13 billion, with unamortized debt issuance costs of $17 million and $20 million, respectively, in Long-term debt. For the three and six months ended June 30, 2025, the Condensed Consolidated Statements of Income reflected the total interest expense of approximately $23 million and $46 million, respectively. For the three and six months ended June 30, 2024, the total interest expense recorded was immaterial to the Condensed Consolidated Statements of Income.

For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K. As of June 30, 2025, none of the conditions allowing holders of the Convertible Notes to convert had been met.

NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the six months ended June 30, 2025 and 2024.

Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, $350 million was contributed on March 28, 2024, and $664 million was contributed on March 31, 2025. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2025, the Utility recorded $63 million and $139 million for amortization of the regulatory asset and liability, respectively, in the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2024, the Utility recorded $82 million and $162 million for amortization of the regulatory asset and liability, respectively, in the Condensed Consolidated Statements of Income.

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


	SB 901 securitization regulatory asset
(in millions)	2025		2024
Balance at January 1	$	5,194	$	5,249
Amortization	(55)		(19)
Balance at June 30	$	5,139	$	5,230


	SB 901 securitization regulatory liability
(in millions)	2025		2024
Balance at January 1	$	(6,295)	$	(6,628)
Amortization	194		180
Additions(1)	(44)		(9)
Balance at June 30	$	(6,145)	$	(6,457)

(1) Includes $44 million and $9 million of returns on investments in the customer credit trust expected to be credited to customers for the six months ended June 30, 2025 and 2024, respectively.

NOTE 6: EQUITY

Dividends

Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of PG&E Corporation’s and the Utility’s Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant.

Utility

On each of November 29, 2024 and February 20, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 18 and May 15, 2025, to holders of record as of January 31 and April 30, 2025. On May 22, 2025, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, payable on August 15, 2025, to holders of record as of July 31, 2025.

On each of February 20 and May 22, 2025, the Board of Directors of the Utility declared common stock dividends of $575 million, which were paid to PG&E Corporation on March 18 and May 30, 2025, respectively.

PG&E Corporation

On each of November 29, 2024, February 20, and May 22, 2025, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.025 per share, each declaration totaling $55 million, which were paid on January 15, April 15, and July 15, 2025, to holders of record as of December 31, 2024, March 31, and June 30, 2025, respectively.

On December 12, 2024, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.7167 per mandatory convertible preferred share, totaling $23 million, which was paid on February 27, 2025, to holders of record as of February 14, 2025. On February 20, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, which was paid on May 29, 2025, to holders of record as of May 15, 2025. On May 22, 2025, the Board of Directors of PG&E Corporation declared a cash dividend in the amount of $0.75 per mandatory convertible preferred share, totaling $24 million, payable on September 1, 2025, to holders of record as of August 15, 2025.

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions, except per share amounts)	2025		2024		2025		2024
Income available for common shareholders	$	521	$	520	$	1,128	$	1,252
Weighted average common shares outstanding, basic(1)	2,198		2,137		2,196		2,136
Add incremental shares from assumed conversions:
Employee share-based compensation	5		5		5		5

Weighted average common shares outstanding, diluted	2,203		2,142		2,201		2,141
Total income per common share, diluted	$	0.24	$	0.24	$	0.51	$	0.58

(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive. For the three and six months ended June 30, 2025, the calculation of outstanding common shares on a diluted basis excluded the impacts of the mandatory convertible preferred stock, which was antidilutive.

NOTE 8: DERIVATIVES

Use of Derivative Instruments

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

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the Cost of electricity or the Cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:


		Contract Volume at
Underlying Product	Instruments	June 30, 2025	December 31, 2024
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	293,476,836	179,257,247
	Options	53,165,000	37,717,500
Electricity (MWh)	Forwards, futures, and swaps	8,729,140	8,576,078
	Options	1,878,000	1,663,200
	Congestion Revenue Rights (3)	103,445,748	123,040,895

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

As of June 30, 2025, the Utility’s outstanding derivative balances were as follows:


	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	162	$	(11)	$	12	$	163
Noncurrent assets – other	223		—		—		223
Current liabilities – other	(105)		11		—		(94)
Noncurrent liabilities – other	(104)		—		—		(104)
Total commodity risk	$	176	$	—	$	12	$	188

As of December 31, 2024, the Utility’s outstanding derivative balances were as follows:


	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	186	$	(16)	$	—	$	170
Other noncurrent assets – other	233		—		—		233
Current liabilities – other	(152)		16		—		(136)
Noncurrent liabilities – other	(167)		—		—		(167)
Total commodity risk	$	100	$	—	$	—	$	100

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

Some of the Utility’s derivative instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of June 30, 2025, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 9: FAIR VALUE MEASUREMENTS

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

Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
Level 3 – Unobservable inputs which are supported by little or no market activities.

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

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.


	Fair Value Measurements
	At June 30, 2025
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	338	$	—	$	—	$	—	$	338

Pacific Energy Risk Solutions, LLC
Short-term investments	979		—		—		—		979
Total Pacific Energy Risk Solutions, LLC	979		—		—		—		979
Nuclear decommissioning trusts
Short-term investments	46		—		—		—		46
Global equity securities	2,433		—		—		—		2,433
Fixed-income securities	1,277		1,051		—		—		2,328
Assets measured at NAV	—		—		—		—		24
Total nuclear decommissioning trusts (2)	3,756		1,051		—		—		4,831
Customer credit trust
Short-term investments	16		—		—		—		16
Global equity securities	473		—		—		—		473
Fixed-income securities	88		358		—		—		446
Total customer credit trust	577		358		—		—		935
Price risk management instruments (Note 8)
Electricity	—		48		312		3		363
Gas	—		25		—		(2)		23
Total price risk management instruments	—		73		312		1		386
Rabbi trusts
Short-term investments	112		—		—		—		112
Global equity securities	4		—		—		—		4

Life insurance contracts	—		66		—		—		66
Total rabbi trusts	116		66		—		—		182
Long-term disability trust
Short-term investments	4		—		—		—		4
Assets measured at NAV	—		—		—		—		129
Total long-term disability trust	4		—		—		—		133
TOTAL ASSETS	$	5,770	$	1,548	$	312	$	1	$	7,784
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	24	$	176	$	(5)	$	195
Gas	—		9		—		(6)		3
TOTAL LIABILITIES	$	—	$	33	$	176	$	(11)	$	198

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.

(2) Represents amount before deducting $809 million primarily related to deferred taxes on appreciation of investment value.


	Fair Value Measurements
	At December 31, 2024
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	826	$	—	$	—	$	—	$	826
Pacific Energy Risk Solutions, LLC
Short-term investments	905		—		—		—		905
Total Pacific Energy Risk Solutions, LLC	905		—		—		—		905
Nuclear decommissioning trusts
Short-term investments	53		—		—		—		53
Global equity securities	2,228		—		—		—		2,228
Fixed-income securities	1,250		1,027		—		—		2,277
Assets measured at NAV	—		—		—		—		22
Total nuclear decommissioning trusts (2)	3,531		1,027		—		—		4,580
Customer credit trust
Short-term investments	1		—		—		—		1
Global equity securities	186		—		—		—		186
Fixed-income securities	46		144		—		—		190
Total customer credit trust	233		144		—		—		377
Price risk management instruments (Note 8)
Electricity	—		26		383		(6)		403
Gas	—		10		—		(10)		—
Total price risk management instruments	—		36		383		(16)		403
Rabbi trusts
Short-term investments	107		—		—		—		107
Global equity securities	6		—		—		—		6
Life insurance contracts	—		66		—		—		66
Total rabbi trusts	113		66		—		—		179
Long-term disability trust
Short-term investments	4		—		—		—		4
Assets measured at NAV	—		—		—		—		130
Total long-term disability trust	4		—		—		—		134
TOTAL ASSETS	$	5,612	$	1,273	$	383	$	(16)	$	7,404
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	37	$	248	$	(6)	$	279
Gas	—		34		—		(10)		24
TOTAL LIABILITIES	$	—	$	71	$	248	$	(16)	$	303

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.

(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the six months ended June 30, 2025 or 2024.

Trust Assets

Assets Measured at Fair Value

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

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

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

Assets Measured at NAV Using Practical Expedient

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

Pacific Energy Risk Solutions, LLC

Investments held in Pacific Energy Risk Solutions, LLC primarily include short-term investments that are U.S. government securities classified as Level 1.

Price Risk Management Instruments

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

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

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

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

Level 3 Measurements and Uncertainty Analysis

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

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 8 above.


	Fair Value (in millions)
	At June 30, 2025				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities			Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	257	$	100	Market approach	CRR auction prices	$ (57) - 54 / 2
Power purchase agreements	$	55	$	76	Discounted cash flow	Forward prices	$ 16 - 110 / 62

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.


	Fair Value (in millions)
	At December 31, 2024				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities			Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	366	$	121	Market approach	CRR auction prices	$ (951) - 50,044 / 2
Power purchase agreements	$	17	$	127	Discounted cash flow	Forward prices	$ 0 - 126 / 47

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2025 and 2024, respectively:


	Price Risk Management Instruments
(in millions)	2025		2024
Asset balance as of April 1	$	126	$	145
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	10		13
Asset balance as of June 30	$	136	$	158

(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.


	Price Risk Management Instruments
(in millions)	2025		2024
Asset balance as of January 1	$	127	$	191
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	9		(33)
Asset balance as of June 30	$	136	$	158

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, and customer deposits approximate their carrying values as of June 30, 2025 and December 31, 2024, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):


	At June 30, 2025				At December 31, 2024
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	5,352	$	5,490	$	5,358	$	5,829
Utility	38,162		34,319		37,812		34,532

(1) As of June 30, 2025, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes was $2.1 billion.

Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of June 30, 2025
Nuclear decommissioning trusts
Short-term investments	$	46	$	—	$	—	$	46
Global equity securities	372		2,091		(6)		2,457
Fixed-income securities	2,341		44		(57)		2,328
Total (1)	$	2,759	$	2,135	$	(63)	$	4,831
As of December 31, 2024
Nuclear decommissioning trusts
Short-term investments	$	54	$	—	$	(1)	$	53
Global equity securities	353		1,907		(10)		2,250
Fixed-income securities	2,341		20		(84)		2,277
Total (1)	$	2,748	$	1,927	$	(95)	$	4,580

(1) Represents amounts before deducting $809 million and $747 million as of June 30, 2025 and December 31, 2024, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:


	As of
(in millions)	June 30, 2025
Less than 1 year	$	13
1–5 years	780
5–10 years	556
More than 10 years	979
Total maturities of fixed-income securities	$	2,328

The following table provides a summary of activity for the fixed-income and equity securities:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2025		2024		2025		2024
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	501	$	587	$	779	$	1,044
Gross realized gains on securities	4		70		6		111
Gross realized losses on securities	(11)		(19)		(17)		(30)

Customer Credit Trust

The following table provides a summary of equity securities and available-for-sale debt securities:


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of June 30, 2025
Customer credit trust
Short-term investments	$	16	$	—	$	—	$	16
Global equity securities	397		80		(4)		473
Fixed-income securities	444		4		(2)		446
Total	$	857	$	84	$	(6)	$	935
As of December 31, 2024
Customer credit trust
Short-term investments	$	1	$	—	$	—	$	1
Global equity securities	161		28		(3)		186
Fixed-income securities	193		1		(4)		190
Total	$	355	$	29	$	(7)	$	377

The fair value of fixed-income securities by contractual maturity is as follows:


	As of
(in millions)	June 30, 2025
Less than 1 year	$	—
1–5 years	116
5–10 years	63
More than 10 years	267
Total maturities of fixed-income securities	$	446

The following table provides a summary of activity for the fixed-income and equity securities:


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2025		2024		2025		2024
Proceeds from sales and maturities of customer credit trust investments	$	97	$	93	$	196	$	174
Gross realized gains on securities	2		—		5		8
Gross realized losses on securities	(8)		(1)		(11)		(2)

NOTE 10: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

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

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the loss accruals in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility.

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

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

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further complaints. However, the applicable statutes of limitations have expired for the 2019 Kincade fire and 2021 Dixie fire, except for the 2021 Dixie fire USFS statute of limitations, which expires in 2027. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

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

If the liability for wildfires were to exceed $1.0 billion in the aggregate in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, except that claims related to the 2019 Kincade fire are subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through June 30, 2025.


Payments (in millions)
2019 Kincade Fire	$	1,177

2021 Dixie Fire	1,624
2022 Mosquito Fire	63
Total at June 30, 2025	$	2,864

2019 Kincade Fire

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

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

As of July 23, 2025, PG&E Corporation and the Utility are aware of approximately 135 complaints on behalf of at least 2,989 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024, the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.

PG&E Corporation and the Utility are also aware of a complaint on behalf of Geysers Power Company, Calpine Corporation, and CPN Insurance Corporation. The court previously scheduled a trial on their claims. Since then, the parties entered into a settlement agreement, and the court vacated the trial date on April 23, 2025.

On October 11, 2022, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.225 billion as of December 31, 2024 (before available insurance). In the first quarter of 2025, PG&E Corporation and the Utility recorded additional charges of $50 million. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during the second quarter of 2025 of $50 million for an aggregate liability of $1.325 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses represent the best estimate of the liability and do not include any claims related to Cal OES or any punitive damages.

The following table presents changes in the best estimate of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2024.


Loss Accrual (in millions)
Balance at December 31, 2024	$	267
Accrued Losses	100
Payments	(219)
Balance at June 30, 2025	$	148

The Utility has fully collected its liability insurance coverage for third-party liability attributable to the 2019 Kincade fire, which was for an aggregate amount of $430 million.

2021 Dixie Fire

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

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

As of July 23, 2025, PG&E Corporation and the Utility are aware of approximately 184 complaints on behalf of at least 8,894 individual plaintiffs related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. The court has scheduled and vacated numerous bellwether trial dates, including the previously scheduled bellwether trial date of June 23, 2025.

The Collins Pine Company and a group of timber companies filed a complaint against PG&E Corporation and the Utility on April 10, 2024. PG&E Corporation and the Utility answered this complaint on May 28, 2024.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer and motion to strike portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer. On April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On April 30, 2025, in response to the Court of Appeal’s request, Cal Fire filed an opposition to the Utility’s writ. The Utility filed a reply to the opposition on May 9, 2025. As of July 30, 2025, the writ remains pending with the Court of Appeal.

On February 7, 2023, the Utility entered into a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

PG&E Corporation and the Utility are aware of a separate putative class complaint. After PG&E Corporation and the Utility demurred to the putative class complaint, the court issued an order abating the case unless the plaintiffs amended the complaint, which the plaintiffs did on February 12, 2025. On March 18, 2025, PG&E Corporation and the Utility filed an answer, and on April 18, 2025 filed an amended answer. On April 28, 2025, the plaintiffs filed a demurrer and a motion to strike PG&E Corporation and the Utility’s answer. Those motions are set for hearing on October 1, 2025. The court set December 1, 2025 as the deadline for the plaintiffs to move for class certification.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.925 billion as of December 31, 2024 (before available recoveries). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during the second quarter of 2025 of $150 million for an aggregate liability of $2.075 billion (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.075 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring costs, or (v) any other amounts that are not reasonably estimable.

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

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2024.


Loss Accrual (in millions)
Balance at December 31, 2024	$	567
Accrued Losses	150
Payments	(265)
Balance at June 30, 2025	$	452

As of June 30, 2025, the Utility recorded an insurance receivable of $523 million for probable insurance recoveries in connection with the 2021 Dixie fire.

The Utility recorded an aggregate Wildfire Fund receivable of $1.075 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $445 million as of June 30, 2025. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. As of June 30, 2025, the Utility also recorded a $95 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $526 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA.

2022 Mosquito Fire

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

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

The cause of the 2022 Mosquito fire remains under investigation by the USFS, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is ongoing.

As of July 23, 2025, PG&E Corporation and the Utility are aware of approximately 26 complaints on behalf of at least 2,716 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and a group of six public entities have each filed complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. On April 24, 2024, PG&E Corporation and the Utility filed cross-complaints against PCWA, alleging that conduct by PCWA was a substantial cause of the 2022 Mosquito fire. The cross-complaints seek property damages, indemnification, attorneys’ fees, and other damages. The court has set individual claimant bellwether trial dates for November 7, 2025 and April 13, 2026.

On May 28, 2025, the Utility executed an amendment to a tolling agreement with Cal OES, extending the agency’s time to file a complaint until June 5, 2026.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million as of December 31, 2024 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during the second quarter of 2025 of $150 million for an aggregate liability of $250 million (before available insurance).

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

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


Loss Accrual (in millions)
Balance at December 31, 2024	$	82
Accrued Losses	150
Payments	(45)
Balance at June 30, 2025	$	187

As of June 30, 2025, the Utility recorded an insurance receivable of $251 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of June 30, 2025, the Utility also recorded a $6 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $54 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

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

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of June 30, 2025 are:


Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	523	$	251
FERC TO rates	95		6
WEMA	526		54
Wildfire Fund	1,075		—
Probable recoveries at June 30, 2025 (1)	$	2,219	$	311

(1) Includes legal costs of $125 million and $54 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of June 30, 2025.

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

Insurance

Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.

Insurance Receivable

As of June 30, 2025, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $523 million and $251 million in connection with the 2021 Dixie fire and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2024:


Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2024	$	27	$	90	$	117
Accrued insurance recoveries	(5)		161		156
Reimbursements	—		(29)		(29)
Balance at June 30, 2025	$	22	$	222	$	244

Regulatory Recovery

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

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

FERC TO Rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of June 30, 2025, the Utility recorded reductions of $95 million and $6 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of June 30, 2025, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $526 million and $54 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund under AB 1054

On July 12, 2019, AB 1054 became law. The law provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund. Eligible claims are claims for third-party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate arising from wildfires in any Coverage Year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. The accrued Wildfire Fund receivable as of June 30, 2025 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. This reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the IOU’s electric transmission and distribution rate base in the year of the prudency determination. A utility would not be required to reimburse the Wildfire Fund for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Utility, the disallowance cap would be approximately $4.7 billion for 2025. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2025 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 11, 2024, the OEIS approved the Utility’s 2024 application and issued the Utility’s 2024 safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts in the fund are exhausted. The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating electric IOUs for a 10-year period.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. AB 1054 authorizes the reimbursement of funds where a participating utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.

As of June 30, 2025, PG&E Corporation and the Utility recorded $625 million and $5 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claims paid by the Wildfire Fund received, for the 2021 Dixie fire since December 31, 2024:


Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2024	$	756
Accrued Wildfire Fund recoveries	150
Claims paid by Wildfire Fund	(276)
Balance at June 30, 2025	$	630

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

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

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

Wildfire-Related Securities Claims in District Court

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

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain former officers and directors, and the underwriters. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint.

On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation.

On August 21, 2024, the District Court entered an order setting a briefing schedule for renewed motions to dismiss the third amended complaint. Opening briefs were filed on October 24, 2024, opposition briefs were filed December 20, 2024, and reply briefs were filed January 31, 2025.

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

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

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

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

PG&E Corporation and the Utility have engaged in settlement efforts with respect to the Subordinated Claims. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Emergence Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Emergence Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. Such claims could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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

On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims.

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

Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against certain directors and officers in the securities class actions.

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

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

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

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

On August 20, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust. The Butte County Superior Court has since continued the hearing to November 14, 2025.

NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS

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

CPUC and FERC Matters

2022 WMCE Interim Rate Relief Subject to Refund

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

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. 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 for such requested rate relief. Cost recovery requested in the 2022 WMCE 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.

2023 WMCE Interim Rate Relief Subject to Refund

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 the 2023 WMCE 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 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 the 2023 WMCE 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.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

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.

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 remaining $172 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.

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters totaled $86 million and $74 million as of June 30, 2025 and December 31, 2024, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10 above. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Tax Matters

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The Internal Revenue Service (“IRS”) is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. On June 4, 2024, the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. As a result, in the year ended December 31, 2024, PG&E Corporation determined that it is no longer more likely than not that its deduction related to a portion of the customer bill credits would ultimately be sustained. Accordingly, PG&E Corporation has decreased its Income tax benefit by $70 million in the year ended December 31, 2024 related to state and federal income taxes. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:


	Balance at
(in millions)	June 30, 2025		December 31, 2024
Topock natural gas compressor station	$	339	$	294
Hinkley natural gas compressor station	97		97
Former MGP sites owned by the Utility or third parties (1)	764		782
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	74		76
Fossil fuel-fired generation facilities and sites (3)	18		18
Total environmental remediation liability	$	1,292	$	1,267

(1) Primarily driven by the following sites: San Francisco Beach Street, Napa, and San Francisco East Harbor.

(2) Primarily driven by Geothermal Landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

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

The Utility’s environmental remediation liability as of June 30, 2025, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. As of June 30, 2025, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

Natural Gas Compressor Station Sites

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

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018, and the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. It is reasonably possible that the Utility’s undiscounted future costs associated with the Topock site may increase by as much as $203 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSMA, where 90% of the costs are recovered through rates.

Hinkley Site

The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take action to meet interim cleanup targets. It is reasonably possible that the Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $136 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $576 million if the extent of contamination or necessary remediation at identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. It is reasonably possible that the Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $76 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSMA, where 90% of the costs are recovered through rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. It is reasonably possible that the Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $15 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for DCPP. For the Humboldt Bay independent spent fuel storage installation, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K.

Purchase Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. As of December 31, 2024, the Utility had undiscounted future expected obligations of approximately $33 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2024 Form 10-K. During the six months ended June 30, 2025, several power purchase agreements that were previously signed by the Utility were approved by the CPUC and met major operational milestones, resulting in additional undiscounted future expected obligations of approximately $2.6 billion over the next 25 years.

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