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

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


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

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

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


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

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)


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

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


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

Wildfire Fund expense	156		234

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

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

Other noncurrent assets and liabilities	(181)		19
Net cash provided by operating activities	2,972		2,460
Cash Flows from Investing Activities
Capital expenditures	(4,936)		(4,680)


Proceeds from sales and maturities of nuclear decommissioning trust investments	1,044		751
Purchases of nuclear decommissioning trust investments	(1,082)		(802)
Proceeds from sales and maturities of customer credit trust investments	174		304
Purchases of customer credit investments	(435)		—
Other	10		7
Net cash used in investing activities	(5,225)		(4,420)
Cash Flows from Financing Activities
Borrowings under credit facilities	5,528		5,536
Repayments under credit facilities	(4,827)		(7,665)
Repayments under term loan credit facilities	(100)		—



Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $9 and $61 at respective dates	2,259		4,690
Repayments of long-term debt	(450)		(389)




Repayment of AB 1054 recovery bonds	(23)		(14)
Repayment of SB 901 recovery bonds	(64)		(67)

Common stock dividends paid	(43)		—
Proceeds from DWR loan	600		—
Other	(7)		(16)
Net cash provided by financing activities	2,873		2,075
Net change in cash, cash equivalents, and restricted cash	620		115
Cash, cash equivalents, and restricted cash at January 1	932		947


Cash, cash equivalents, and restricted cash at June 30	$	1,552	$	1,062
Less: Restricted cash and restricted cash equivalents	(237)		(257)
Cash and cash equivalents at June 30	$	1,315	$	805


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,199)	$	(1,068)

Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	921	$	860
Operating lease liabilities arising from ROU assets	1		208

Financing lease liabilities arising from obtaining ROU assets	15		—

Changes to PG&E Corporation common stock and treasury stock in connection with share exchanges with the Fire Victim Trust	—		(1,219)
DWR loan forgiveness and performance-based disbursements	47		67
Common stock dividends declared but not yet paid	21		—

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)


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

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,
	2024		2023		2024		2023
Net Income	$	565	$	480	$	1,346	$	1,106
Other Comprehensive Income
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $0, $0, $1, and $2, respectively)	—		—		(1)		6
Total other comprehensive income (loss)	—		—		(1)		6
Comprehensive Income	$	565	$	480	$	1,345	$	1,112

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, 2024		December 31, 2023
ASSETS
Current Assets
Cash and cash equivalents	$	1,060	$	442
Restricted cash (includes $227 million and $282 million related to VIEs at respective dates)	236		294
Accounts receivable
Customers (net of allowance for doubtful accounts of $349 million and $445 million at respective dates) (includes $1.6 billion and $1.7 billion related to VIEs, net of allowance for doubtful accounts of $349 million and $445 million at respective dates)	1,982		2,048
Accrued unbilled revenue (includes $1.8 billion and $1.1 billion related to VIEs at respective dates)	2,038		1,254
Regulatory balancing accounts	6,698		5,660
Other	1,406		1,495
Regulatory assets	258		300
Inventories
Gas stored underground and fuel oil	56		65
Materials and supplies	767		805
Wildfire Fund asset	305		450
Other	1,677		1,374
Total current assets	16,483		14,187
Property, Plant, and Equipment
Electric	83,458		80,345
Gas	30,642		29,830
Construction work in progress	4,752		4,452
Financing lease ROU asset and other	786		787
Total property, plant, and equipment	119,638		115,414
Accumulated depreciation	(34,396)		(33,093)
Net property, plant, and equipment	85,242		82,321
Other Noncurrent Assets
Regulatory assets	16,230		17,189
Customer credit trust	505		233
Nuclear decommissioning trusts	3,740		3,574
Operating lease ROU asset	573		598
Wildfire Fund asset	4,289		4,297
Income taxes receivable	—		22
Other (includes noncurrent accounts receivable of $78 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $16 million and $0 at respective dates)	3,321		2,934
Total other noncurrent assets	28,658		28,847
TOTAL ASSETS	$	130,383	$	125,355

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, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	4,972	$	3,971
Long-term debt, classified as current (includes $179 million and $176 million related to VIEs at respective dates)	1,578		1,376
Accounts payable
Trade creditors	2,147		2,307
Regulatory balancing accounts	2,151		1,669
Other	854		820
Operating lease liabilities	81		80
Financing lease liabilities	779		259
Interest payable (includes $67 million and $67 million related to VIEs at respective dates)	663		621
Wildfire-related claims	939		1,422
Other	4,007		4,391
Total current liabilities	18,171		16,916
Noncurrent Liabilities
Long-term debt (includes $10.4 billion and $10.5 billion related to VIEs at respective dates)	48,058		46,376
Regulatory liabilities	19,900		19,444
Pension and other postretirement benefits	394		405
Asset retirement obligations	5,564		5,512
Deferred income taxes	2,978		2,436
Operating lease liabilities	492		518
Financing lease liabilities	45		554
Other	4,164		3,670
Total noncurrent liabilities	81,595		78,915
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	31,275		30,570
Reinvested earnings	(2,224)		(2,613)
Accumulated other comprehensive loss	(14)		(13)
Total shareholders’ equity	30,617		29,524
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	130,383	$	125,355

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,
	2024		2023
Cash Flows from Operating Activities
Net income	$	1,346	$	1,106
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,075		2,074
Bad debt expense	135		293
Allowance for equity funds used during construction	(84)		(82)
Deferred income taxes and tax credits, net	529		(278)

Wildfire Fund expense	156		234

Other	(154)		64
Effect of changes in operating assets and liabilities:
Accounts receivable	(960)		1,595
Wildfire-related insurance receivable	196		347
Inventories	47		(46)
Accounts payable	408		110
Wildfire-related claims	(483)		(656)

Other current assets and liabilities	(652)		(223)
Regulatory assets, liabilities, and balancing accounts, net	734		(1,931)

Other noncurrent assets and liabilities	(179)		20
Net cash provided by operating activities	3,114		2,627
Cash Flows from Investing Activities
Capital expenditures	(4,936)		(4,680)


Proceeds from sales and maturities of nuclear decommissioning trust investments	1,044		751
Purchases of nuclear decommissioning trust investments	(1,082)		(802)
Proceeds from sales and maturities of customer credit trust investments	174		304
Purchases of customer credit investments	(435)		—

Other	10		7
Net cash used in investing activities	(5,225)		(4,420)
Cash Flows from Financing Activities
Borrowings under credit facilities	5,528		5,536
Repayments under credit facilities	(4,827)		(7,665)
Repayments under term loan credit facilities	(100)		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $9 and $61 at respective dates	2,259		4,690
Repayments of long-term debt	(450)		(375)


Repayment of AB 1054 recovery bonds	(23)		(14)
Repayment of SB 901 recovery bonds	(64)		(67)
Preferred stock dividends paid	(7)		(7)
Common stock dividends paid	(950)		(875)
Equity contribution from PG&E Corporation	705		560

Proceeds from DWR loan	600		—
Other	—		(11)
Net cash provided by financing activities	2,671		1,772
Net change in cash, cash equivalents, and restricted cash	560		(21)
Cash, cash equivalents, and restricted cash at January 1	736		822
Cash, cash equivalents, and restricted cash at June 30	$	1,296	$	801
Less: Restricted cash and restricted cash equivalents	(236)		(256)
Cash and cash equivalents at June 30	$	1,060	$	545


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,083)	$	(911)

Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	921	$	860
Operating lease liabilities arising from obtaining ROU assets	1		208
Financing lease liabilities arising from obtaining ROU assets	15		—

DWR loan forgiveness and performance-based disbursements	47		67

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, 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 Balance at June 30, 2024	$	258	$	1,322	$	31,275	$	(2,224)	$	(14)	$	30,617


	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2022	$	258	$	1,322	$	29,280	$	(3,368)	$	(8)	$	27,484
Net income	—		—		—		626		—		626
Other comprehensive income	—		—		—		—		6		6
Equity contribution	—		—		310		—		—		310
Common stock dividend	—		—		—		(425)		—		(425)
Preferred stock dividend requirement	—		—		—		(3)		—		(3)
Balance at March 31, 2023	$	258	$	1,322	$	29,590	$	(3,170)	$	(2)	$	27,998
Net income	—		—		—		480		—		480
Equity contribution	—		—		250		—		—		250
Common stock dividend	—		—		—		(450)		—		(450)
Preferred stock dividend requirement	—		—		—		(4)		—		(4)
Balance at June 30, 2023	$	258	$	1,322	$	29,840	$	(3,144)	$	(2)	$	28,274

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. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information as of December 31, 2023 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 2023 Form 10-K. This quarterly report on Form 10-Q should be read in conjunction with the 2023 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

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2024		2023		2024		2023
Electric
Revenue from contracts with customers
Residential	$	1,516	$	1,404	$	3,315	$	2,693
Commercial	1,655		1,283		3,160		2,427
Industrial	441		375		854		728
Agricultural	439		314		619		469
Public street and highway lighting	27		20		52		39
Other, net (1)	798		(121)		919		(78)
Total revenue from contracts with customers - electric	4,876		3,275		8,919		6,278
Regulatory balancing accounts (2)	(418)		577		(409)		1,693
Total electric operating revenue	$	4,458	$	3,852	$	8,510	$	7,971

Natural gas
Revenue from contracts with customers
Residential	$	213	$	691	$	1,730	$	2,574
Commercial	187		189		560		702
Transportation service only	424		398		899		842
Other, net (1)	(138)		(257)		(202)		(410)
Total revenue from contracts with customers - gas	686		1,021		2,987		3,708
Regulatory balancing accounts (2)	842		417		350		(180)
Total natural gas operating revenue	1,528		1,438		3,337		3,528
Total operating revenues	$	5,986	$	5,290	$	11,847	$	11,499

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

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

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of June 30, 2024, 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 $65 million and $135 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, 2024, respectively. For the three and six months ended June 30, 2023, expected credit losses were $154 million and $293 million, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset account. As of June 30, 2024, the RUBA current balancing accounts receivable balance was $98 million, and CPPMA and FERC noncurrent regulatory asset balances were $6 million and $73 million, respectively. As of December 31, 2023, the RUBA current balancing accounts receivable balance was $507 million, and CPPMA and FERC noncurrent regulatory asset balances were $5 million and $78 million, respectively. The RUBA current balancing account balance decreased from December 31, 2023 to June 30, 2024 primarily due to the annual electric and gas true-up which allows the Utility to recover approximately $500 million in undercollections from residential customers in 2024.

Other Receivables and Available-For-Sale Debt Securities

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

As of June 30, 2024, 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 six months ended June 30, 2024 and 2023. The Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the three and six months ended June 30, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Condensed Consolidated Statements of Income.

DWR Loan Agreement

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

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to Accounting Standards Codification (“ASC”) 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs to support the extension of Diablo Canyon, the Utility will recognize 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 provides a summary of where the 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)	2024		2023		2024		2023
Long-term debt:
Beginning Balance - DWR loan outstanding	$	296	$	279	$	98	$	312

Proceeds received	368		—		600		—

Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(17)		(19)		(39)		(52)
Operating and maintenance expense - Loan forgiveness and other adjustments	12		—		12		—

Other current liabilities:
Performance-based disbursements deferred	(8)		(15)		(20)		(15)

Long-term debt:
Ending Balance - DWR loan outstanding	$	651	$	245	$	651	$	245

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to Diablo Canyon as part of the DOE’s Civil Nuclear Credit Program. The Utility will use these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the Diablo Canyon 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 will recognize such funding as income and will record a receivable related to government grants. 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 Diablo Canyon.

Variable Interest Entities

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

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, 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, 2024 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2024 and December 31, 2023, the SPV had net accounts receivable of $3.5 billion and $2.7 billion, respectively, and outstanding borrowings of $1.5 billion, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

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

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, 2024 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A senior secured recovery bonds. As of June 30, 2024 and December 31, 2023, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets.

SB 901 Securitization

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

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the six months ended June 30, 2024 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of June 30, 2024 and December 31, 2023, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.3 billion, 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, 2024, 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, 2024, it did not consolidate any of them.

The Lakeside Building

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

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

Contributions to the Wildfire Fund Established Pursuant to AB 1054

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

PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and as required by additional information. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire. PG&E Corporation and the Utility initially estimated a period of coverage of 15 years. In the first quarter of 2024, the annual assessment resulted in the expected life of the Wildfire Fund increasing to 20 years after incorporating 2023 loss information into the dataset with no events triggering a claim against the Wildfire Fund.

As of June 30, 2024, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $754 million in Other noncurrent liabilities, $305 million in Current assets - Wildfire Fund asset, and $4.3 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended June 30, 2024 and 2023, the Utility recorded amortization and accretion expense of $78 million and $117 million, respectively. During the six months ended June 30, 2024 and 2023, the Utility recorded amortization and accretion expense of $156 million and $234 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. As of June 30, 2024, PG&E Corporation and the Utility recorded $500 million in Accounts receivable - other and $100 million in Other noncurrent assets in the Condensed Consolidated Balance Sheets, for Wildfire Fund receivables related to the 2021 Dixie fire.

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

Pension and Other Post-Retirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2024 and 2023 were as follows:


	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2024		2023		2024		2023
Service cost for benefits earned (1)	$	99	$	95	$	11	$	9
Interest cost	229		229		18		19
Expected return on plan assets	(254)		(246)		(35)		(33)
Amortization of prior service (credit)	(1)		(1)		—		—
Amortization of net actuarial (gain) loss	1		—		(5)		(4)
Net periodic benefit cost	74		77		(11)		(9)
Regulatory account transfer (2)	(9)		(6)		—		—
Total	$	65	$	71	$	(11)	$	(9)

(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)	2024		2023		2024		2023
Service cost for benefits earned (1)	$	198	$	190	$	21	$	19
Interest cost	458		457		36		37
Expected return on plan assets	(507)		(491)		(70)		(66)
Amortization of prior service cost (credit)	(2)		(2)		1		1
Amortization of net actuarial (gain) loss	1		—		(11)		(9)
Net periodic benefit cost	148		154		(23)		(18)
Regulatory account transfer (2)	(19)		(13)		—		—
Total	$	129	$	141	$	(23)	$	(18)

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

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

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

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

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

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


	Pension Benefits		Other Benefits		Customer Credit 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 gain (loss)	—		—		—		—
Ending balance	$	(28)	$	18	$	1	$	(9)

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


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Three Months Ended June 30, 2023
Beginning balance	$	(12)	$	18	$	(1)	$	5
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $0, and $0, respectively)	—		—		—		—
Amortization of net actuarial gain (net of taxes of $0, $1, and $0, respectively)	—		(3)		—		(3)
Regulatory account transfer (net of taxes of $1, $1, and $0, respectively)	—		3		—		3
Net current period other comprehensive gain (loss)	—		—		—		—
Ending balance	$	(12)	$	18	$	(1)	$	5


	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)


	Pension Benefits		Other Benefits		Customer Credit Trust		Total
(in millions, net of income tax)	Six Months Ended June 30, 2023
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0, and $2, respectively)	—		—		5		5
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $0, and $0, respectively)	(1)		1		—		—
Amortization of net actuarial gain (net of taxes of $0, $2, and $0, respectively)	—		(7)		—		(7)
Regulatory account transfer (net of taxes of $1, $2, and $0, respectively)	1		6		—		7
Net current period other comprehensive gain	—		—		5		5
Ending balance	$	(12)	$	18	$	(1)	$	5

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

Accounting Standards Issued But Not Yet Adopted

Segment Reporting

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which amends the existing guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, 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.

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 income taxes paid disaggregated by jurisdiction. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2024. 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, 2024		December 31, 2023
Pension benefits	$	330	$	348
Environmental compliance costs	1,152		1,218
Price risk management	166		160
Catastrophic event memorandum account	1,047		1,074
Wildfire-related accounts	2,518		2,915
Deferred income taxes	3,952		3,543
Financing costs	189		196
SB 901 securitization	5,230		5,249
General rate case memorandum accounts	693		1,291
Other	953		1,195
Total noncurrent regulatory assets	$	16,230	$	17,189

Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:


	Balance at
(in millions)	June 30, 2024		December 31, 2023
Cost of removal obligations	$	8,527	$	8,191
Public purpose programs	1,332		1,238
Employee benefit plans	1,043		1,032
Transmission tower wireless licenses	330		384
SFGO sale	119		185
SB 901 securitization	6,457		6,628
Wildfire self-insurance	600		407
Other	1,492		1,379
Total noncurrent regulatory liabilities	$	19,900	$	19,444

Regulatory Balancing Accounts

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


	Balance at
(in millions)	June 30, 2024		December 31, 2023
Electric distribution	$	1,759	$	1,092
Electric transmission	95		99
Gas distribution and transmission	158		144
Energy procurement	1,554		1,002
Public purpose programs	270		137
Wildfire-related accounts	508		729
Insurance premium costs	37		227
Residential uncollectibles balancing accounts	98		507
Catastrophic event memorandum account	304		413
General rate case memorandum accounts	1,114		1,097
Other	801		213
Total regulatory balancing accounts receivable	$	6,698	$	5,660


	Balance at
(in millions)	June 30, 2024		December 31, 2023
Electric transmission	$	130	$	200
Gas distribution and transmission	63		224
Energy procurement	714		77
Public purpose programs	498		299
SFGO sale	51		79
Wildfire-related accounts	264		125
Nuclear decommissioning adjustment mechanism	133		216
Other	298		449
Total regulatory balancing accounts payable	$	2,151	$	1,669

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 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, 2024:


(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2028	$	4,400	(1)	$	(2,450)	$	(416)	$	1,534
Utility Receivables Securitization Program (2)	June 2026	1,500		(3)	(1,500)		—		—		(3)
PG&E Corporation revolving credit facility	June 2026	500			—		—		500
Total credit facilities		$	6,400		$	(3,950)	$	(416)	$	2,034

(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 16, 2024, the Utility amended its existing term loan agreement to combine its $400 million 2-year tranche loan maturing April 19, 2024 and its $125 million 364-day tranche loan maturing April 16, 2024 into a single loan of $525 million maturing April 15, 2025. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 26, 2024, the Utility amended its existing receivables securitization program to, among other things, extend the scheduled termination date from June 9, 2025 to June 26, 2026.

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

Long-Term Debt Issuances and Redemptions

Utility

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

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”). For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K. As of June 30, 2024, 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. In the context of the customer harm threshold decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit, which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 9 below). The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues in the Condensed Consolidated Statements of Income for the six months ended June 30, 2024 and 2023.

Upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, $350 million was contributed on March 28, 2024, and $650 million is required to be contributed no later than March 31, 2025 unless certain conditions are met requiring an earlier contribution or unless otherwise ordered by the CPUC. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sold PG&E Corporation common stock shares it held, the SB 901 securitization regulatory liability increased accordingly. 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, 2024, the Utility recorded $82 million and $162 million respectively, for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. During the three months ended June 30, 2023, the Utility recorded SB 901 securitization charges, net, of $289 million for tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock and $71 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. During the six months ended June 30, 2023, the Utility recorded SB 901 securitization charges, net, of $562 million for tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock and $158 million for amortization of the regulatory asset and liability 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)	2024		2023
Balance at January 1	$	5,249	$	5,378
Amortization	(19)		(82)
Balance at June 30	$	5,230	$	5,296


	SB 901 securitization regulatory liability
(in millions)	2024		2023
Balance at January 1	$	(6,628)	$	(5,800)
Amortization	180		240
Additions(1)	(9)		(567)
Balance at June 30	$	(6,457)	$	(6,127)

(1) Includes $9 million and $5 million of returns on investments in the customer credit trust expected to be credited to customers for the six months ended June 30, 2024 and 2023, respectively.

NOTE 6: EQUITY

Dividends

Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. The CPUC has granted the Utility a temporary waiver from compliance with its authorized capital structure until 2025 for the financing in place upon the Utility’s emergence from Chapter 11.

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

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

PG&E Corporation

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

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)	2024		2023		2024		2023
Income available for common shareholders	$	520	$	406	$	1,252	$	975
Weighted average common shares outstanding, basic	2,137		2,019		2,136		2,005
Add incremental shares from assumed conversions:
Employee share-based compensation	5		6		5		6
Equity units	—		114		—		126
Weighted average common shares outstanding, diluted	2,142		2,139		2,141		2,137
Total income per common share, diluted	$	0.24	$	0.19	$	0.58	$	0.46

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. In addition, the Convertible Notes (as defined in Note 4) issued in December 2023 did not have a material impact on the calculation of diluted EPS.

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, 2024	December 31, 2023
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	274,047,264	196,063,296
	Options	50,622,500	30,695,000
Electricity (MWh)	Forwards, futures, and swaps	9,989,125	9,169,967
	Options	1,355,200	92,400
	Congestion Revenue Rights (3)	147,542,438	170,465,674

(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, 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	$	171	$	(8)	$	21	$	184
Other noncurrent assets – other	225		—		—		225
Current liabilities – other	(143)		8		1		(134)
Noncurrent liabilities – other	(166)		—		—		(166)
Total commodity risk	$	87	$	—	$	22	$	109

As of December 31, 2023, 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	$	134	$	(8)	$	50	$	176
Other noncurrent assets – other	280		—		—		280
Current liabilities – other	(172)		8		46		(118)
Noncurrent liabilities – other	(160)		—		—		(160)
Total commodity risk	$	82	$	—	$	96	$	178

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, 2024, 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, 2024
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments (2)	$	1,235	$	—	$	—	$	—	$	1,235

Nuclear decommissioning trusts
Short-term investments	38		—		—		—		38
Global equity securities	2,248		—		—		—		2,248
Fixed-income securities	1,185		1,015		—		—		2,200
Assets measured at NAV	—		—		—		—		20
Total nuclear decommissioning trusts (3)	3,471		1,015		—		—		4,506
Customer credit trust
Short-term investments	348		—		—		—		348
Global equity securities	49		—		—		—		49
Fixed-income securities	21		87		—		—		108
Total customer credit trust	418		87		—		—		505
Price risk management instruments (Note 8)
Electricity	—		28		351		2		381
Gas	—		17		—		11		28
Total price risk management instruments	—		45		351		13		409
Rabbi trusts
Short-term investments	105		—		—		—		105
Global equity securities	5		—		—		—		5

Life insurance contracts	—		66		—		—		66
Total rabbi trusts	110		66		—		—		176
Long-term disability trust
Short-term investments	5		—		—		—		5
Assets measured at NAV	—		—		—		—		133
Total long-term disability trust	5		—		—		—		138
TOTAL ASSETS	$	5,239	$	1,213	$	351	$	13	$	6,969
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	107	$	193	$	(4)	$	296
Gas	—		9		—		(5)		4
TOTAL LIABILITIES	$	—	$	116	$	193	$	(9)	$	300

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

(2) Includes $608 million in money market funds to be used for the administration of wildfire liability self-insurance. These assets are held by Pacific Energy Risk Solutions, LLC, a wholly-owned subsidiary of the Utility and captive insurance company. For more information see “Self-insurance” in Note 10 below.

(3) Represents amount before deducting $766 million primarily related to deferred taxes on appreciation of investment value.


	Fair Value Measurements
	December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	203	$	—	$	—	$	—	$	203
Nuclear decommissioning trusts
Short-term investments	52		—		—		—		52
Global equity securities	2,144		—		—		—		2,144
Fixed-income securities	1,168		909		—		—		2,077
Assets measured at NAV	—		—		—		—		18
Total nuclear decommissioning trusts (2)	3,364		909		—		—		4,291
Customer credit trust
Short-term investments	49		—		—		—		49
Global equity securities	71		—		—		—		71
Fixed-income securities	29		84		—		—		113
Total customer credit trust	149		84		—		—		233
Price risk management instruments (Note 8)
Electricity	—		7		404		(1)		410
Gas	—		3		—		43		46
Total price risk management instruments	—		10		404		42		456
Rabbi trusts
Short-term investments	102		—		—		—		102
Global equity securities	5		—		—		—		5
Life insurance contracts	—		65		—		—		65
Total rabbi trusts	107		65		—		—		172
Long-term disability trust
Short-term investments	7		—		—		—		7
Assets measured at NAV	—		—		—		—		139
Total long-term disability trust	7		—		—		—		146
TOTAL ASSETS	$	3,830	$	1,068	$	404	$	42	$	5,501
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	43	$	213	$	(6)	$	250
Gas	—		76		—		(48)		28
TOTAL LIABILITIES	$	—	$	119	$	213	$	(54)	$	278

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

(2) Represents amount before deducting $717 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, 2024 and 2023.

Trust Assets

Assets Measured at Fair Value

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

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

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

Assets Measured at NAV Using Practical Expedient

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

Price Risk Management Instruments

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

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

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

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

Level 3 Measurements and Uncertainty Analysis

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

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, 2024				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities			Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	327	$	117	Market approach	CRR auction prices	$ (17,980.60) - 17,974.20 / 1.57
Power purchase agreements	$	24	$	76	Discounted cash flow	Forward prices	$ 0.27 - 140.45 / 54.93

(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, 2023				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities			Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	357	$	134	Market approach	CRR auction prices	$ (923.72) - 16,696.90 / 1.43
Power purchase agreements	$	47	$	79	Discounted cash flow	Forward prices	$ 0.86 - 189.80 / 60.03

(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, 2024 and 2023, respectively:


	Price Risk Management Instruments
(in millions)	2024		2023
Asset balance as of April 1	$	145	$	212
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	13		(86)
Asset balance as of June 30	$	158	$	126

(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)	2024		2023
Asset balance as of January 1	$	191	$	199
Net realized and unrealized losses:
Included in regulatory assets and liabilities or balancing accounts (1)	(33)		(73)
Asset balance as of June 30	$	158	$	126

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of June 30, 2024 and December 31, 2023, 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, 2024				At December 31, 2023
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	4,356	$	4,088	$	4,548	$	4,695
Utility	37,700		33,588		35,909		32,866

(1) As of June 30, 2024, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.1 billion and $2.2 billion, respectively.

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, 2024
Nuclear decommissioning trusts
Short-term investments	$	38	$	—	$	—	$	38
Global equity securities	361		1,918		(11)		2,268
Fixed-income securities	2,259		28		(87)		2,200
Total (1)	$	2,658	$	1,946	$	(98)	$	4,506
As of December 31, 2023
Nuclear decommissioning trusts
Short-term investments	$	52	$	—	$	—	$	52
Global equity securities	381		1,792		(11)		2,162
Fixed-income securities	2,103		60		(86)		2,077
Total (1)	$	2,536	$	1,852	$	(97)	$	4,291

(1) Represents amounts before deducting $766 million and $717 million as of June 30, 2024 and December 31, 2023, 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, 2024
Less than 1 year	$	9
1–5 years	713
5–10 years	516
More than 10 years	962
Total maturities of fixed-income securities	$	2,200

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)	2024		2023		2024		2023
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	587	$	474	$	1,044	$	751
Gross realized gains on securities	70		37		111		42
Gross realized losses on securities	(19)		(10)		(30)		(18)

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, 2024
Customer credit trust
Short-term investments	$	348	$	—	$	—	$	348
Global equity securities	35		15		(1)		49
Fixed-income securities	109		—		(1)		108
Total	$	492	$	15	$	(2)	$	505
As of December 31, 2023
Customer credit trust
Short-term investments	$	49	$	—	$	—	$	49
Global equity securities	56		16		(1)		71
Fixed-income securities	111		2		—		113
Total	$	216	$	18	$	(1)	$	233

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


	As of
(in millions)	June 30, 2024
Less than 1 year	$	—
1–5 years	16
5–10 years	27
More than 10 years	65
Total maturities of fixed-income securities	$	108

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)	2024		2023		2024		2023
Proceeds from sales and maturities of customer credit trust investments	$	93	$	135	$	174	$	304
Gross realized gains on securities	—		6		8		8
Gross realized losses on securities	(1)		(5)		(2)		(10)

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. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

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

PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further complaints. The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their 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 would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through June 30, 2024.


Payments (in millions)
2019 Kincade Fire	$	834

2021 Dixie Fire	1,044
2022 Mosquito Fire	15
Total at June 30, 2024	$	1,893

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 17, 2024, PG&E Corporation and the Utility are aware of approximately 132 complaints on behalf of at least 2,907 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. The court has also scheduled a damages-only trial for a single claim for February 3, 2025. PG&E Corporation and the Utility are also aware of a complaint on behalf of Geysers Power Company, Calpine Corporation, and CPN Insurance Corporation.

In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022. On August 8, 2023, PG&E Corporation and the Utility entered into an agreement with Cal Fire to resolve its claims arising from the 2019 Kincade fire. On January 24, 2024, Cal Fire filed a request to dismiss its complaint with prejudice in the coordinated proceeding, which the court entered.

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

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.125 billion as of December 31, 2023 (before available insurance). The aggregate liability remained unchanged as of June 30, 2024.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.125 billion do not include, among other things: (i) any punitive damages, (ii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, or (iii) any other amounts that are not reasonably estimable.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2023.


Loss Accrual (in millions)
Balance at December 31, 2023	$	458
Accrued Losses	—
Payments	(167)
Balance at June 30, 2024	$	291

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million, which was fully collected as of December 31, 2023.

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.

On October 9, 2023, the SED submitted for adoption by the CPUC a draft resolution approving an Administrative Consent Order and Agreement between the SED and the Utility (the “Dixie ACO”). The Dixie ACO would resolve the SED’s investigation into the 2021 Dixie fire. The Dixie ACO provides that the Utility would (i) pay $2.5 million to California’s General Fund; (ii) pay $2.5 million to tribes impacted by the 2021 Dixie fire; (iii) and undertake an initiative to transition to electronic records for specified patrols and inspections of distribution facilities, at an approximate cost of $40 million over five years, and the Utility may not seek recovery of such costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2021 Dixie fire. The Dixie ACO states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. The Dixie ACO also states that the parties to it intend that it shall not affect whether the Utility may obtain recovery of costs and expenses incurred in connection with the 2021 Dixie fire, including for amounts drawn from the Wildfire Fund or otherwise sought through a cost recovery application to the CPUC. On February 2, 2024, the CPUC issued a final decision approving the Dixie ACO. In connection with the Dixie ACO, PG&E Corporation and the Utility recorded a liability of $5 million reflected in Other current liabilities on the Condensed Consolidated Financial Statements as of June 30, 2024. For the recordkeeping initiative costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

As of July 17, 2024, PG&E Corporation and the Utility are aware of approximately 172 complaints on behalf of at least 8,519 individual plaintiffs and a separate putative class complaint related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. On March 15, 2024, the court scheduled a new trial date for October 14, 2024. The court also set a subsequent trial date for February 24, 2025. PG&E Corporation and the Utility are also aware of a complaint on behalf of the Collins Pine Company and a group of timber companies.

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. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience to date in settling the claims of individual plaintiffs, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.6 billion as of December 31, 2023 (before available insurance). The aggregate liability remained unchanged as of June 30, 2024.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.6 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies including for state or federal fire suppression costs and damages related to federal land, (iv) 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 from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national 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 range of losses for claims arising from the 2021 Dixie fire since December 31, 2023.


Loss Accrual (in millions)
Balance at December 31, 2023	$	870
Accrued Losses	—
Payments	(313)
Balance at June 30, 2024	$	557

As of June 30, 2024, the Utility recorded an insurance receivable of $525 million for probable insurance recoveries in connection with the 2021 Dixie fire.

As of June 30, 2024, the Utility recorded a Wildfire Fund receivable of $600 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. As of June 30, 2024, the Utility also recorded a $93 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 $494 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 and the United States Department of Justice, and PG&E Corporation and the Utility are cooperating with the investigation. 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.

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

As of July 17, 2024, PG&E Corporation and the Utility are aware of approximately eight complaints on behalf of at least 329 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the PCWA, a complaint on behalf of the Middle Fork Project Finance Authority, a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency. 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.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded a liability in the aggregate amount of $100 million as of December 31, 2023 (before available insurance). The aggregate liability remained unchanged as of June 30, 2024.

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

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2022 Mosquito fire since December 31, 2023.


Loss Accrual (in millions)
Balance at December 31, 2023	$	85
Accrued Losses	—
Payments	—
Balance at June 30, 2024	$	85

As of June 30, 2024, the Utility recorded an insurance receivable of $83 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of June 30, 2024, the Utility also recorded a $7 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 $53 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

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

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of June 30, 2024 are:


Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	525	$	83
FERC TO rates	93		7
WEMA	494		53
Wildfire Fund	600		—
Probable recoveries at June 30, 2024 (1)	$	1,712	$	143

(1) Includes legal costs of $106 million and $43 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of June 30, 2024.

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

Through June 30, 2024, PG&E Corporation and the Utility recorded $525 million and $83 million for probable insurance recoveries 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:


Insurance Receivable (in millions)	2021 Dixie fire		2022 Mosquito fire		Total
Balance at December 31, 2023	$	326	$	63	$	389
Accrued insurance recoveries	(1)		21		20
Reimbursements	(211)		—		(211)
Balance at June 30, 2024	$	114	$	84	$	198

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, 2024, the Utility recorded reductions of $93 million and $7 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, 2024, 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 $494 million and $53 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 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, 2024 reflects an expectation that the Coverage Year will be based on the calendar year.

Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $4.1 billion based on its 2024 equity rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On January 22, 2024, the OEIS approved the Utility’s 2023 application and issued the Utility’s 2023 safety certification.

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

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. 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, 2024, PG&E Corporation and the Utility recorded $500 million and $100 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

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

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

Wildfire-Related Securities Claims in District Court

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

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

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain then-current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act 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 current and former officers and former directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action.

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. The parties stipulated to a stay, and on May 16, 2023, the District Court entered an order staying the Orbis action pursuant to all of the same terms and conditions in the District Court’s September 30, 2022 order staying the In re PG&E Corporation Securities Litigation action.

On May 3, 2024, the Court of Appeals for the Ninth Circuit issued an opinion vacating the stay in the In re PG&E Corporation Securities Litigation action, and remanding the case to the District Court with instructions for the District Court to weigh all the relevant interests in determining whether a stay is appropriate. The District Court has set a status conference for August 27, 2024, regarding mediation and a potential schedule for further briefing on the pending motions to dismiss.

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 September 20, 2024.

NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS

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

CPUC and FERC Matters

Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates through TO rate cases. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund.

Rates under the TO rate case for 2017 (“TO18”) were in effect from March 1, 2017 through February 28, 2018. Rates under the TO rate case for 2018 (“TO19”) were in effect from March 1, 2018 through April 30, 2019. Rates under the TO rate case for 2019 (“TO20”) were in effect from May 1, 2019 through December 31, 2023.

On October 15, 2020, the FERC issued an order addressing substantive disputed issues concerning TO18 including the direct assignment of common plant costs, impact of the TCJA on January and February 2018 rates, and depreciation and ordered additional briefing on the appropriate ROE. On April 15, 2021, the FERC issued an order on rehearing setting aside its earlier determination on the TCJA and determining that the lower tax rates in the TCJA applied to the TO18 rates in January and February 2018. On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%.

The Utility and other parties have filed appeals of the FERC’s TO18 orders. The appeals are currently pending before the D.C. Circuit Court of Appeals and are being held in abeyance. Requests for rehearing of the ROE decision are still pending at the FERC. On May 31, 2024, the Utility and certain intervenors filed a settlement at the FERC regarding TO18.

On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility regarding TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision.

TO20 was a formula rate, which means the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year based on a formula, without a separate rate case. On August 17, 2020, and December 30, 2020, FERC accepted a partial settlement and final settlement, respectively, in the TO20 proceedings. Several issues in the settlements, such as the direct assignment of common plant costs, are contingent on the outcome of a final, non-appealable TO18 decision.

Parties have protested the Utility’s annual updates under the formula rate, and these protests are pending before the FERC. On October 24, 2023, the Utility filed a waiver request for certain inputs to the formula rate related to the cost of long-term debt and certain underwriting fees, which the FERC denied on December 22, 2023. On January 22, 2024, the Utility filed a request for reconsideration, which the FERC denied on February 22, 2024. On March 28, 2024, the Utility filed a petition for review in the Court of Appeals for the District of Columbia. On May 23, 2024, the FERC issued a substantive order on rehearing again denying the Utility’s waiver request, and the Utility withdrew the petition for review.

Aside from the ultimate outcome of the ROE rehearing request and the direct assignment of common plant costs, the FERC’s orders in the TO18 proceeding are not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, or cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the direct assignment of common plant costs, will also be incorporated into the Utility’s TO19 and TO20 rate cases. The Utility has established regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the second quarter of 2024 of approximately $484 million pending a final and non-appealable TO18 decision. Based on the settlement, a portion of the direct assignment of common plant costs are expected to be recovered at the CPUC in a separate application, and as a result, as of June 30, 2024, the Utility had recorded approximately $233 million to Regulatory assets.

2022 WMCE Interim Rate Relief Subject to Refund

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

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

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

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.

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

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 $80 million and $89 million as of June 30, 2024 and December 31, 2023, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Tax Matters

The Internal Revenue Service (“IRS”) is auditing PG&E Corporation’s tax returns for 2015 through 2018. The State of California is auditing PG&E Corporation’s tax returns for 2015 through 2019. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for gas transmission and distribution lines, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits, in connection with its decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. 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 gas transmission and distribution lines and customer bill credits are nondeductible fines or penalties. As a result, in the quarter ended June 30, 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 will ultimately be sustained. Accordingly, PG&E Corporation has decreased its Income tax benefit by $70 million during the quarter ended June 30, 2024 related to state and federal income taxes. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

CZU Lightning Complex Fire Notices of Violation

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

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

Environmental Remediation Contingencies

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


	Balance at
(in millions)	June 30, 2024		December 31, 2023
Topock natural gas compressor station	$	287	$	276
Hinkley natural gas compressor station	104		104
Former MGP sites owned by the Utility or third parties (1)	810		809
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	75		107
Fossil fuel-fired generation facilities and sites (3)	18		19
Total environmental remediation liability	$	1,294	$	1,315

(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 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, 2024, 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, 2024, 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 $213 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 $127 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 $647 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 $75 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 $20 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the 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 Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for Diablo Canyon. For 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 Diablo Canyon. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $42 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $5 million. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 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, 2023, the Utility had undiscounted future expected obligations of approximately $32 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K.

Oakland Headquarters Lease and Purchase

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building (the “Property”) to serve as the Utility’s principal administrative headquarters (the “Lease”).

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

The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of June 30, 2024, approximately 715,000 rentable square feet of the leased premises has been made available for use by the Utility.

As of June 30, 2024, the Utility has recorded $781 million in Financing lease ROU assets, $62 million in accumulated amortization, $180 million in leasehold improvements, net of accumulated amortization, which includes $101 million that was provided to the Utility as lease incentives, and $777 million in current Financing lease liabilities in the Condensed Consolidated Financial Statements primarily related to the Lease, as amended.

For more information about the Lease, see “Oakland Headquarters Lease and Purchase*”* in Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2023 Form 10-K.

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