Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)


	Year ended December 31,
	2023		2022		2021
Operating Revenues
Electric	$	17,424	$	15,060	$	15,131
Natural gas	7,004		6,620		5,511
Total operating revenues	24,428		21,680		20,642
Operating Expenses
Cost of electricity	2,443		2,756		3,232
Cost of natural gas	1,754		2,100		1,149
Operating and maintenance	11,924		9,809		10,200
SB 901 securitization charges, net	1,267		608		—
Wildfire-related claims, net of recoveries	64		237		258
Wildfire Fund expense	567		477		517
Depreciation, amortization, and decommissioning	3,738		3,856		3,403
Total operating expenses	21,757		19,843		18,759
Operating Income	2,671		1,837		1,883
Interest income	606		162		20
Interest expense	(2,850)		(1,917)		(1,601)
Other income, net	272		394		457
Reorganization items, net	—		—		(11)
Income Before Income Taxes	699		476		748
Income tax provision (benefit)	(1,557)		(1,338)		836
Net Income (Loss)	2,256		1,814		(88)
Preferred stock dividend requirement of subsidiary	14		14		14
Income (Loss) Attributable to Common Shareholders	$	2,242	$	1,800	$	(102)
Weighted Average Common Shares Outstanding, Basic	2,064		1,987		1,985
Weighted Average Common Shares Outstanding, Diluted	2,138		2,132		1,985
Net Income (Loss) Per Common Share, Basic	$	1.09	$	0.91	$	(0.05)
Net Income (Loss) Per Common Share, Diluted	$	1.05	$	0.84	$	(0.05)

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	Year ended December 31,
	2023		2022		2021
Net Income (Loss)	$	2,256	$	1,814	$	(88)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $6, $8, and $3, at respective dates)	(16)		21		7
Net unrealized losses on available-for-sale securities (net of taxes of $3, $3, and $0, respectively)	8		(6)		—
Total other comprehensive income (loss)	(8)		15		7
Comprehensive Income (Loss)	2,248		1,829		(81)
Preferred stock dividend requirement of subsidiary	14		14		14
Comprehensive Income (Loss) Attributable to Common Shareholders	$	2,234	$	1,815	$	(95)

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)



	Balance at
	December 31, 2023		December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	635	$	734
Restricted cash (includes $282 million and $201 million related to VIEs at respective dates)	297		213
Accounts receivable
Customers (net of allowance for doubtful accounts of $445 million and $166 million at respective dates) (includes $1.7 billion and $2.5 billion related to VIEs, net of allowance for doubtful accounts of $445 million and $166 million at respective dates)	2,048		2,645
Accrued unbilled revenue (includes $1.1 billion and $1.2 billion related to VIEs at respective dates)	1,254		1,304
Regulatory balancing accounts	5,660		3,264
Other	1,494		1,624
Regulatory assets	300		296
Inventories
Gas stored underground and fuel oil	65		91
Materials and supplies	805		751
Wildfire Fund asset	450		460
Other	1,375		1,433
Total current assets	14,383		12,815
Property, Plant, and Equipment
Electric	80,345		74,772
Gas	29,830		28,226
Construction work in progress	4,452		4,137
Financing lease ROU asset and other	787		19
Total property, plant, and equipment	115,414		107,154
Accumulated depreciation	(33,093)		(30,946)
Net property, plant, and equipment	82,321		76,208
Other Noncurrent Assets
Regulatory assets	17,189		16,443
Customer credit trust	233		745
Nuclear decommissioning trusts	3,574		3,297
Operating lease ROU asset	598		1,311
Wildfire Fund asset	4,297		4,847
Income taxes receivable	24		9
Other (includes noncurrent accounts receivable of $0 and $17 million related to VIEs, net of noncurrent allowance for doubtful accounts of $0 and $1 million at respective dates)	3,079		2,969
Total other noncurrent assets	28,994		29,621
TOTAL ASSETS	$	125,698	$	118,644

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)



	Balance at
	December 31, 2023		December 31, 2022
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	3,971	$	2,055
Long-term debt, classified as current (includes $176 million and $168 million related to VIEs at respective dates)	1,376		2,268
Accounts payable
Trade creditors	2,309		2,888
Regulatory balancing accounts	1,669		1,658
Other	851		778
Operating lease liabilities	80		231
Financing lease liabilities	259		—
Interest payable (includes $67 million and $116 million related to VIEs at respective dates)	679		626
Wildfire-related claims	1,422		1,912
Other	4,698		3,372
Total current liabilities	17,314		15,788
Noncurrent Liabilities
Long-term debt (includes $10.5 billion and $10.3 billion related to VIEs at respective dates)	50,975		47,742
Regulatory liabilities	19,444		17,630
Pension and other postretirement benefits	476		231
Asset retirement obligations	5,512		5,912
Deferred income taxes	1,980		2,732
Operating lease liabilities	518		1,243
Financing lease liabilities	554		—
Other	3,633		4,291
Total noncurrent liabilities	83,092		79,781
Equity
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,133,597,758 and 1,987,784,948 shares outstanding at respective dates	30,374		32,887
Treasury stock, at cost; 0 and 247,743,590 shares at respective dates	—		(2,517)
Reinvested earnings	(5,321)		(7,542)
Accumulated other comprehensive loss	(13)		(5)
Total shareholders’ equity	25,040		22,823
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	25,292		23,075
TOTAL LIABILITIES AND EQUITY	$	125,698	$	118,644

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year ended December 31,
	2023		2022		2021
Cash Flows from Operating Activities
Net income (loss)	$	2,256	$	1,814	$	(88)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,738		3,856		3,403
Bad Debt Expense	636		143		154
Allowance for equity funds used during construction	(179)		(184)		(133)
Deferred income taxes and tax credits, net	(765)		(452)		1,783
Reorganization items, net	—		—		(73)
Wildfire fund expense	568		477		517
Disallowed capital expenditures	—		15		—
Other	(116)		517		248
Effect of changes in operating assets and liabilities:
Accounts receivable	(369)		(757)		(589)
Wildfire-related insurance receivable	358		453		(723)
Inventories	(28)		(246)		(32)
Accounts payable	(90)		627		117
Wildfire-related claims	(489)		(810)		472

Other current assets and liabilities	397		17		244
Regulatory assets, liabilities, and balancing accounts, net	(429)		(1,131)		(2,266)

Contributions to Wildfire fund	(193)		(193)		(193)
Other noncurrent assets and liabilities	(548)		(425)		(579)
Net cash provided by operating activities	4,747		3,721		2,262
Cash Flows from Investing Activities
Capital expenditures	(9,714)		(9,584)		(7,689)
Proceeds from sale of the SFGO	—		—		749
Proceeds from sales and maturities of nuclear decommissioning trust investments	2,235		3,316		1,678
Purchases of nuclear decommissioning trust investments	(2,252)		(3,208)		(1,702)
Proceeds from sales and maturities of customer credit trust investments	556		250		—
Purchases of customer credit trust investments	—		(1,022)		—
Other	13		34		59
Net cash used in investing activities	(9,162)		(10,214)		(6,905)
Cash Flows from Financing Activities





Borrowings under credit facilities	10,675		10,130		9,730
Repayments under credit facilities	(10,540)		(9,750)		(9,976)
Borrowings under term loan credit facilities	2,100		—		—
Repayments under term loan credit facilities	(2,181)		—		—
Credit facilities financing fees	—		—		(9)

Short-term debt financing, net of issuance costs of $0, $0, and $1 at respective dates	—		—		300
Short-term debt matured	—		(300)		(1,450)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $67, $29, and $33 at respective dates	5,483		4,271		4,624


Repayment of long-term debt	(3,075)		(5,968)		(87)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees of $0, $36 and $0 at respective dates	—		7,464		—
Repayment of SB 901 recovery bonds	(130)		(33)		—
Proceeds from issuance of AB 1054 recovery bonds, net of financing fees of $0, $11 and $10 at respective dates	—		972		850
Repayment of AB 1054 recovery bonds	(38)		(18)		—
Proceeds from DWR loan, net of performance based incentives earned of $0, $38, and $0 at respective dates	—		312		—
Proceeds from issuance of convertible notes, net of discount and issuance costs of $27, $0, and $0 at respective dates	2,123		—		—
Proceeds from sale of future revenue from transmission tower license sales, net of fees	—		—		370



Other	(17)		53		(29)
Net cash provided by financing activities	4,400		7,133		4,323
Net change in cash, cash equivalents, and restricted cash	(15)		640		(320)
Cash, cash equivalents, and restricted cash at January 1	947		307		627
Cash, cash equivalents, and restricted cash at December 31	$	932	$	947	$	307
Less: Restricted cash and restricted cash equivalents	(297)		(213)		(16)
Cash and cash equivalents at December 31	$	635	$	734	$	291


Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(2,286)	$	(1,607)	$	(1,404)
Income taxes, net	—		—		99
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,105	$	1,174	$	1,311
Operating lease liabilities arising from obtaining ROU assets	269		529		100
Financing lease liabilities arising from obtaining ROU assets	52		—		—
Reclassification of operating lease liabilities to financing lease liabilities	913		—		—
DWR loan forgiveness and performance-based disbursements	214		—		—
Changes to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement	(2,517)		(2,337)		4,854
Common stock dividends declared but not yet paid	21		—		—

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

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, 2020	1,984,678,673	$	30,224	—	$	—	$	(9,196)	$	(27)	$	21,001	$	252	$	21,253
Net loss	—	—		—	—		(88)		—		(88)		—		(88)
Other comprehensive income	—	—		—	—		—		7		7		—		7
Common stock issued, net (1)	721,867	4,854		—	—		—		—		4,854		—		4,854
Treasury stock acquired	—	—		477,743,590	(4,854)		—		—		(4,854)		—		(4,854)
Stock-based compensation amortization	—	51		—	—		—		—		51		—		51
Balance at December 31, 2021	1,985,400,540	$	35,129	477,743,590	$	(4,854)	$	(9,284)	$	(20)	$	20,971	$	252	$	21,223
Net income	—	—		—	—		1,814		—		1,814		—		1,814
Other comprehensive income	—	—		—	—		—		15		15		—		15
Common stock issued, net	2,384,408	(2,337)		—	—		—		—		(2,337)		—		(2,337)
Treasury stock disposition	—	—		(230,000,000)	2,337		—		—		2,337		—		2,337
Stock-based compensation amortization	—	95		—	—		—		—		95		—		95
Preferred stock dividend requirement of subsidiary in arrears	—	—		—	—		(59)		—		(59)		—		(59)
Preferred stock dividend requirement of subsidiary	—	—		—	—		(13)		—		(13)		—		(13)
Balance at December 31, 2022	1,987,784,948	$	32,887	247,743,590	$	(2,517)	$	(7,542)	$	(5)	$	22,823	$	252	$	23,075
Net income	—	—		—	—		2,256		—		2,256		—		2,256
Other comprehensive loss	—	—		—	—		—		(8)		(8)		—		(8)
Common stock issued, net	145,812,810	(2,517)		—	—		—		—		(2,517)		—		(2,517)
Treasury stock disposition	—	—		(247,743,590)	2,517		—		—		2,517		—		2,517
Stock-based compensation amortization	—	4		—	—		—		—		4		—		4
Common stock dividends declared	—	—		—	—		(21)		—		(21)		—		(21)
Preferred stock dividend requirement of subsidiary	—	—		—	—		(14)		—		(14)		—		(14)
Balance at December 31, 2023	2,133,597,758	$	30,374	—	$	—	$	(5,321)	$	(13)	$	25,040	$	252	$	25,292

(1) Excludes 477,743,590 shares of common stock owned by the Utility. For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K .

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in millions)


	Year ended December 31,
	2023		2022		2021
Operating Revenues
Electric	$	17,424	$	15,060	$	15,131
Natural gas	7,004		6,620		5,511
Total operating revenues	24,428		21,680		20,642
Operating Expenses
Cost of electricity	2,443		2,756		3,232
Cost of natural gas	1,754		2,100		1,149
Operating and maintenance	11,913		9,725		10,194
SB 901 securitization charges, net	1,267		608		—
Wildfire-related claims, net of recoveries	64		237		258
Wildfire Fund expense	567		477		517
Depreciation, amortization, and decommissioning	3,738		3,856		3,403
Total operating expenses	21,746		19,759		18,753
Operating Income	2,682		1,921		1,889
Interest income	593		162		22
Interest expense	(2,485)		(1,658)		(1,373)
Other income, net	293		595		512
Reorganization items, net	—		—		(12)
Income Before Income Taxes	1,083		1,020		1,038
Income tax provision (benefit)	(1,461)		(1,206)		900
Net Income	2,544		2,226		138
Preferred stock dividend requirement	14		14		14
Income Attributable to Common Stock	$	2,530	$	2,212	$	124

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	Year ended December 31,
	2023		2022		2021
Net Income	$	2,544	$	2,226	$	138
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $5, $2, and $1, at respective dates)	(12)		6		(4)
Net unrealized losses on available-for-sale securities (net of taxes of $4, $3, and $0, respectively)	7		(5)		—
Total other comprehensive income (loss)	(5)		1		(4)
Comprehensive Income	$	2,539	$	2,227	$	134

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)



	Balance at
	December 31, 2023		December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	442	$	609
Restricted cash (includes $282 million and $201 million related to VIEs at respective dates)	294		213
Accounts receivable
Customers (net of allowance for doubtful accounts of $445 million and $166 million at respective dates) (includes $1.7 billion and $2.5 billion related to VIEs, net of allowance for doubtful accounts of $445 million and $166 million at respective dates)	2,048		2,645
Accrued unbilled revenue (includes $1.1 billion and $1.2 billion related to VIEs at respective dates)	1,254		1,304
Regulatory balancing accounts	5,660		3,264
Other	1,495		1,633
Regulatory assets	300		296
Inventories
Gas stored underground and fuel oil	65		91
Materials and supplies	805		751
Wildfire Fund asset	450		460
Other	1,374		1,421
Total current assets	14,187		12,687
Property, Plant, and Equipment
Electric	80,345		74,772
Gas	29,830		28,226
Construction work in progress	4,452		4,137
Financing lease ROU asset and other	787		18
Total property, plant, and equipment	115,414		107,153
Accumulated depreciation	(33,093)		(30,946)
Net property, plant, and equipment	82,321		76,207
Other Noncurrent Assets
Regulatory assets	17,189		16,443
Customer credit trust	233		745
Nuclear decommissioning trusts	3,574		3,297
Operating lease ROU asset	598		1,311
Wildfire Fund asset	4,297		4,847
Income taxes receivable	22		7
Other (includes noncurrent accounts receivable of $0 and $17 million related to VIEs, net of noncurrent allowance for doubtful accounts of $0 and $1 million at respective dates)	2,934		2,834
Total other noncurrent assets	28,847		29,484
TOTAL ASSETS	$	125,355	$	118,378

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)



	Balance at
	December 31, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	3,971	$	2,055
Long-term debt, classified as current (includes $176 million and $168 million related to VIEs at respective dates)	1,376		2,241
Accounts payable
Trade creditors	2,307		2,886
Regulatory balancing accounts	1,669		1,658
Other	820		747
Operating lease liabilities	80		231
Financing lease liabilities	259		—
Interest payable (includes $67 million and $116 million related to VIEs at respective dates)	621		573
Wildfire-related claims	1,422		1,912
Other	4,391		3,067
Total current liabilities	16,916		15,370
Noncurrent Liabilities
Long-term debt (includes $10.5 billion and $10.3 billion related to VIEs at respective dates)	46,376		43,155
Regulatory liabilities	19,444		17,630
Pension and other postretirement benefits	405		160
Asset retirement obligations	5,512		5,912
Deferred income taxes	2,436		3,090
Operating lease liabilities	518		1,243
Financing lease liabilities	554		—
Other	3,670		4,334
Total noncurrent liabilities	78,915		75,524
Shareholders’ Equity
Preferred stock	258		258
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates	1,322		1,322
Additional paid-in capital	30,570		29,280
Reinvested earnings	(2,613)		(3,368)
Accumulated other comprehensive loss	(13)		(8)
Total shareholders’ equity	29,524		27,484
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	125,355	$	118,378

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year ended December 31,
	2023		2022		2021
Cash Flows from Operating Activities
Net income	$	2,544	$	2,226	$	138
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,738		3,856		3,403
Bad Debt Expense	636		143		154
Allowance for equity funds used during construction	(179)		(184)		(133)
Deferred income taxes and tax credits, net	(663)		(319)		1,846
Reorganization items, net	—		—		(41)
Wildfire Fund expense	568		477		517
Disallowed capital expenditures	—		15		—
Other	(176)		102		172
Effect of changes in operating assets and liabilities:
Accounts receivable	(361)		(763)		(584)
Wildfire-related insurance receivable	358		453		(723)
Inventories	(28)		(246)		(32)
Accounts payable	(90)		627		44
Wildfire-related claims	(489)		(810)		472

Other current assets and liabilities	402		16		251
Regulatory assets, liabilities, and balancing accounts, net	(429)		(1,131)		(2,266)

Contributions to Wildfire Fund	(193)		(193)		(193)
Other noncurrent assets and liabilities	(541)		(438)		(577)
Net cash provided by operating activities	5,097		3,831		2,448
Cash Flows from Investing Activities
Capital expenditures	(9,714)		(9,584)		(7,689)
Proceeds from sale of the SFGO	—		—		749
Proceeds from sales and maturities of nuclear decommissioning trust investments	2,235		3,316		1,678
Purchases of nuclear decommissioning trust investments	(2,252)		(3,208)		(1,702)
Proceeds from sales and maturities of customer credit trust investments	556		250		—
Purchases of customer credit trust investments	—		(1,022)		—
Proceeds from (repayments of) intercompany note to PG&E Corporation	—		145		(145)
Other	13		34		59
Net cash used in investing activities	(9,162)		(10,069)		(7,050)
Cash Flows from Financing Activities




Borrowings under credit facilities	10,675		10,130		9,730
Repayments under credit facilities	(10,540)		(9,750)		(9,976)


Borrowings under term loan credit facilities	2,100		—		—
Credit facilities financing fees	—		—		(9)
Short-term debt financing, net of issuance costs of $0, $0, and $1 at respective dates	—		—		300
Short-term debt matured	—		(300)		(1,450)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $67, $29, and $33 at respective dates	5,483		4,271		4,624
Repayment of long-term debt	(3,075)		(5,941)		(59)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees of $0, $36 and $0 at respective dates	—		7,464		—
Repayment of SB 901 recovery bonds	(130)		(33)		—
Proceeds from AB 1054 recovery bonds, net issuance costs of $0, $11, and $10 at respective dates	—		972		850
Repayment of AB 1054 recovery bonds	(38)		(18)		—
Proceeds from DWR loan, net of performance based incentives earned of $0, $38, and $0 at respective dates	—		312		—
Proceeds from sale of future revenue from transmission tower license sales, net of fees	—		—		370

Preferred stock dividends paid	(14)		(70)		—
Common stock dividends paid	(1,775)		(1,275)		—
Equity contribution from PG&E Corporation	1,290		994		—
Other	3		123		(1)
Net cash provided by financing activities	3,979		6,879		4,379
Net change in cash, cash equivalents, and restricted cash	(86)		641		(223)
Cash, cash equivalents, and restricted cash at January 1	822		181		404
Cash, cash equivalents, and restricted cash at December 31	$	736	$	822	$	181
Less: Restricted cash and restricted cash equivalents	(294)		(213)		(16)
Cash and cash equivalents at December 31	$	442	$	609	$	165


Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(1,977)	$	(1,374)	$	(1,198)
Income taxes, net	—		—		99
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,105	$	1,174	$	1,311
Operating lease liabilities arising from obtaining ROU assets	269		529		100
Financing lease liabilities arising from obtaining ROU assets	52		—		—
Reclassification of operating lease liabilities to financing lease liabilities	913		—		—
DWR loan forgiveness and performance-based disbursements	214		—		—

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

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, 2020	$	258	$	1,322	$	28,286	$	(4,385)	$	(5)	$	25,476
Net income	—		—		—		138		—		138
Other comprehensive loss	—		—		—		—		(4)		(4)
Balance at December 31, 2021	$	258	$	1,322	$	28,286	$	(4,247)	$	(9)	$	25,610
Net income	—		—		—		2,226		—		2,226
Other comprehensive income	—		—		—		—		1		1
Equity contribution	—		—		994		—		—		994
Preferred stock dividend requirement in arrears	—		—		—		(59)		—		(59)
Preferred stock dividend requirement	—		—		—		(13)		—		(13)
Common stock dividend	—		—		—		(1,275)		—		(1,275)
Balance at December 31, 2022	$	258	$	1,322	$	29,280	$	(3,368)	$	(8)	$	27,484
Net income	—		—		—		2,544		—		2,544
Other comprehensive loss	—		—		—		—		(5)		(5)
Equity contribution	—		—		1,290		—		—		1,290
Common stock dividend	—		—		—		(1,775)		—		(1,775)
Preferred stock dividend requirement	—		—		—		(14)		—		(14)
Balance at December 31, 2023	$	258	$	1,322	$	30,570	$	(2,613)	$	(13)	$	29,524

See accompanying Notes to the Consolidated Financial Statements.

NOTES TO THE 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 is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 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 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 Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the 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

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records as regulatory assets costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, 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. These differences have no impact on net income. See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. As of December 31, 2023, the Utility also holds $294 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

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 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:


	Year Ended December 31,
(in millions)		2023		2022		2021
Electric
Revenue from contracts with customers
Residential		$	6,041	$	6,130	$	6,089
Commercial		5,643		5,416		5,042
Industrial		1,784		1,626		1,493
Agricultural		1,413		1,830		1,565
Public street and highway lighting		83		77		73
Other, net (1)		136		(247)		(84)
Total revenue from contracts with customers - electric		15,100		14,832		14,178
Regulatory balancing accounts (2)		2,324		228		953
Total electric operating revenue		$	17,424	$	15,060	$	15,131

Natural gas
Revenue from contracts with customers
Residential		$	3,686	$	3,353	$	2,759
Commercial		1,052		1,005		713
Transportation service only		1,603		1,534		1,346
Other, net (1)		(145)		163		140
Total revenue from contracts with customers - gas		6,196		6,055		4,958
Regulatory balancing accounts (2)		808		565		553
Total natural gas operating revenue		7,004		6,620		5,511
Total operating revenues		$	24,428	$	21,680	$	20,642

(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 December 31, 2023, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

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

Expected credit losses of $636 million, $143 million, and $154 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2023, 2022, and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of 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. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC noncurrent regulatory asset balances were $3 million and $8 million, respectively.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 14 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 December 31, 2023, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.

Inventories

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, materials, and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. See “AFUDC” below. The Utility’s estimated service lives of its property, plant, and equipment were as follows:


	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2023		2022
Electricity generating facilities (1)	3 to 75	$	11,423	$	11,781
Electricity distribution facilities	10 to 70	45,205		41,061
Electricity transmission facilities	15 to 75	17,562		16,413
Natural gas distribution facilities	20 to 60	16,324		15,366
Natural gas transmission and storage facilities	5 to 70	10,496		9,859
General plant and other	5 to 50	9,165		8,518
Financing lease		787		18
Construction work in progress		4,452		4,137
Total property, plant, and equipment		115,414		107,153
Accumulated depreciation		(33,093)		(30,946)
Net property, plant, and equipment (2)		$	82,321	$	76,207

(1) Balance includes nuclear fuel inventories. Nuclear generating facilities have been authorized by the CPUC to be fully depreciated by December 31, 2025. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. See Note 15 below.

(2) Includes $1.7 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054.

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments. This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.56% in 2023, 3.74% in 2022, and 3.82% in 2021. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $82 million and $179 million during 2023, $81 million and $184 million during 2022, and $56 million and $133 million during 2021.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2023 and 2022, including nuclear decommissioning obligations:


(in millions)	2023		2022
ARO liability at beginning of year	$	5,912	$	5,298
Liabilities incurred	—		134
Revision in estimated cash flows	(585)		325
Accretion	253		213
Liabilities settled	(68)		(58)
ARO liability at end of year	$	5,512	$	5,912

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 3 below.

The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The ARO liability decreased from $5.9 billion as of December 31, 2022 to $5.5 billion as of December 31, 2023, primarily due to a decrease in nuclear decommissioning and hydroelectric facilities ARO. In the fourth quarter of 2023, the Utility recorded a downward revision to its hydroelectric facilities ARO of $205 million as a result of a revised decommissioning cost estimate.

The total nuclear decommissioning obligation was $4.0 billion as of December 31, 2023 compared to $4.1 billion as of December 31, 2022 based on the cost study performed as part of the 2021 NDCTP. As of December 31, 2023, the Utility recorded a $253 million downward adjustment to the nuclear decommissioning ARO to reflect the CPUC’s decision to approve Diablo Canyon’s extended operations until 2030 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and the Humboldt Bay independent spent fuel storage installation. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility’s nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC.

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable to or recoverable from, respectively, customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.

Government Assistance

PG&E Corporation and the Utility received various government assistance programs during the years ended December 31, 2023 and 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

Assembly Bill 180

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the years ended December 31, 2023 and 2022, the Consolidated Statements of Income reflected $56 million and $0 million, respectively, recorded as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

DWR Loan Agreement

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

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement 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 Consolidated Financial Statements:


(in millions)	2023		2022
Long-term debt:
DWR Loan Outstanding at January 1	$	312	$	—

Proceeds received (1)	—		350

Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(124)		(38)
Operating and maintenance expense - Loan forgiven	(90)		—
Total deduction to Operating Expenses	(214)		(38)

Long-term debt:
DWR Loan Outstanding at December 31	$	98	$	312

(1) On January 11, 2024, the Utility received $233 million in disbursements from the DWR.

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 year ended December 31, 2023, the Consolidated Statements of Income reflected $76 million and $115 million as deductions to Cost of electricity and Operating and maintenance expense, respectively, for income related to government grants for incurred fuel costs and incurred eligible costs to support the extension of Diablo Canyon.

Variable Interest Entities

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

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the 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 year ended December 31, 2023 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2023 and December 31, 2022, the SPV had net accounts receivable of $2.7 billion and $3.6 billion, respectively, and outstanding borrowings of $1.5 billion and $1.2 billion, respectively, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

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

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 year ended December 31, 2023 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 December 31, 2023 and December 31, 2022, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion, included in Long-term debt and Long-term debt, classified as current on the 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 year ended December 31, 2023 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 December 31, 2023 and December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.3 billion and $7.5 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the 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 December 31, 2023, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of December 31, 2023, it did not consolidate any of them.

The Lakeside Building

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

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property. The Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC as it does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to the issued letter of credit as well as the amounts it pays for base rent and certain costs, per the office lease agreement. For more information, see “Recognition of Lease Assets and Liabilities” 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 to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.

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

As of December 31, 2023, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $750 million in Other noncurrent liabilities, $450 million in Current assets - Wildfire Fund asset, and $4.3 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2023 and 2022, the Utility recorded amortization and accretion expense of $567 million and $477 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 Consolidated Statements of Income. As of December 31, 2023, PG&E Corporation and the Utility recorded $325 million and $275 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Wildfire Fund under AB 1054” in Note 14 below.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, “Wildfire-related Contingencies” in Note 14, and “Other Contingencies and Commitments” in Note 15 below.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2023 consisted of the following:


(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $3, respectively)	—		—		8		8
Unrecognized net actuarial gain (loss) (net of taxes of $76, $28 and $0, respectively)	(196)		73		—		(123)
Regulatory account transfer (net of taxes of $70, $28 and $0, respectively)	180		(73)		—		107
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(3)		2		—		(1)
Amortization of net actuarial (gain) loss (net of taxes of $0, $5 and $0, respectively) (1)	1		(14)		—		(13)
Regulatory account transfer (net of taxes of $1, $4 and $0, respectively) (1)	2		12		—		14
Net current period other comprehensive income (loss)	(16)		—		8		(8)
Ending balance	$	(28)	$	18	$	2	$	(8)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 12 below for additional details.

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2022 consisted of the following:


(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassifications:
Unrealized loss on investments (net of taxes of $0, $0 and $3, respectively)	—		—		(6)		(6)
Unrecognized net actuarial gain (loss) (net of taxes of $102, $99 and $0, respectively)	263		(255)		—		8
Regulatory account transfer (net of taxes of $94, $99 and $0, respectively)	(242)		255		—		13
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $2 and $0, respectively) (1)	(3)		5		—		2
Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively)(1)	1		(29)		—		(28)
Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1)	2		24		—		26
Net current period other comprehensive income (loss)	21		—		(6)		15
Ending balance	$	(12)	$	18	$	(6)	$	—

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 12 below for additional details.

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.

Financing Leases

Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the year ended December 31, 2023, the Utility made total fixed cash payments of $142 million for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. Financing leases were immaterial for the year ended December 31, 2022. The majority of the Utility’s financing lease ROU assets and lease liabilities relate to the Oakland Headquarters lease discussed below.

Oakland Headquarters Lease and Purchase

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

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

The Lease also requires the rentable space to be delivered in two phases, with each phase consisting of multiple subphases. As of December 31, 2023, approximately 659,000 rentable square feet of the leased premises has been made available for use by the Utility.

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

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

As of December 31, 2023, the Utility has recorded $787 million in Financing lease ROU assets, $108 million in accumulated amortization, $218 million in leasehold improvements, net of accumulated amortization, which includes $134 million that was provided to the Utility as lease incentives, $259 million in current Financing lease liabilities, and $554 million in noncurrent Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended.

At December 31, 2023, the Utility’s financing lease had a weighted average remaining lease term of 1.6 years and a weighted average discount rate of 6.5%.

The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:


	Year Ended December 31,
(in millions)	2023
Financing lease fixed cost:
Amortization of ROU assets	$	115
Interest on lease liabilities	27
Financing lease variable cost	3
Total financing lease costs	$	145

At December 31, 2023, the Utility’s future expected financing lease payments were as follows:


(in millions)	December 31, 2023
2024	$	305
2025	531
2026	44
2027	—
2028	—
Total lease payments	880
Less imputed interest	(67)
Total	$	813

Operating Leases

Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2023 and 2022, the Utility made total cash payments, including fixed and variable, of $1.9 billion and $2.3 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s operating lease ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below.

At December 31, 2023 and 2022, the Utility’s operating leases had a weighted average remaining lease term of 8.2 years and 19.6 years and a weighted average discount rate of 6.4% and 6.5%, respectively.

The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:


	Year Ended December 31,
(in millions)	2023		2022
Operating lease fixed cost	$	269	$	500
Operating lease variable cost	1,632		1,829
Total operating lease costs	$	1,901	$	2,329

At December 31, 2023, the Utility’s future expected operating lease payments were as follows:


(in millions)	December 31, 2023
2024	$	116
2025	115
2026	112
2027	110
2028	97
Thereafter	256
Total lease payments	806
Less imputed interest	(208)
Total	$	598

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 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 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 December 31,				Recovery Period
(in millions)	2023		2022
Pension benefits (1)	$	348	$	120	Indefinitely
Environmental compliance costs	1,218		1,193		32 years
Utility retained generation (2)	39		86		4 years
Price risk management	160		177		16.5 years
Catastrophic event memorandum account (3)	1,074		1,085		1 - 3 years
Wildfire expense memorandum account (4)	540		439		TBD years
Fire hazard prevention memorandum account (5)	7		79		1 - 2 years
Fire risk mitigation memorandum account (6)	110		65		1 - 3 years
Wildfire mitigation plan memorandum account (7)	541		756		1 - 3 years
Deferred income taxes (8)	3,543		2,730		51 years
Insurance premium costs (9)	1		99		2 - 4 years
Wildfire mitigation balancing account (10)	120		327		1 - 4 years
Vegetation management balancing account (11)	1,538		2,276		1 - 3 years
COVID-19 pandemic protection memorandum accounts (12)	17		26		1 - 3 years
Microgrid memorandum account (13)	59		213		1 - 3 years
Financing costs (14)	196		211		Various
SB 901 securitization (15)	5,249		5,378		30 years
AROs in excess of recoveries (16)	73		120		Various
General rate case memorandum accounts (17)	1,291		—		1 - 2 years
Other	1,065		1,063		Various
Total noncurrent regulatory assets	$	17,189	$	16,443

(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.

(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2023 and 2022, $43 million and $44 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. Recovery of WEMA costs is subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that were approved for recovery in the 2020 WMCE final decision.

(6) Includes incremental costs associated with fire risk mitigation not included in the WMP’s. Recovery of costs incurred during the period from 2020 through 2022 was requested in the 2023 WGSC application, and costs incurred in 2023 will be requested in a future application. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs incurred in 2020 through 2023 and associated with each year’s respective approved WMP. Recovery of costs incurred during the period from 2020 through 2022 was requested in the 2023 WGSC application, and costs incurred in 2023 will be requested in a future application. Also includes the noncurrent portion of costs associated with the 2019 WMP that were approved for recovery in the 2020 WMCE final decision. Recovery of WMPMA costs is subject to CPUC review and approval.

(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.

(9) Represents excess liability insurance premium costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S, respectively.

(10) Represents costs associated with certain wildfire mitigation activities for the period of January 1, 2020 through December 31, 2022. The noncurrent balance includes costs incurred during the 12-month period ending December 31, 2020 that were approved for recovery in the 2021 WMCE final decision. The remaining balance includes costs above 115% of adopted revenue requirements, as authorized in the 2020 GRC rate case, which are subject to CPUC review and approval.

(11) Includes costs associated with certain vegetation management activities for the period of January 1, 2020 through December 31, 2022. The noncurrent balance represents costs above 120% of adopted revenue requirements, as authorized in the 2020 GRC rate case, which are subject to CPUC review and approval.

(12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of December 31, 2023, the Utility had recorded uncollectibles in the amount of $5 million for small business customers. The remaining $12 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

(13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval.

(14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewable and approved in the Utility’s cost of capital or other regulatory filings.

(15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 5 below.

(16) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 11 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods.

(17) The GRC memorandum accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2023 and through the date of the final 2023 GRC decision as authorized by the CPUC in December 2023. These amounts will be recovered in rates over 24 months, beginning January 1, 2024.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2023 and 2022, the Utility had current regulatory liabilities of $1.2 billion and $1.1 billion, respectively. At December 31, 2023, current regulatory liabilities consisted primarily of billed revenues exceeding TO20 transmission revenue requirements. Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets.

Noncurrent Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:


	Balance at December 31,
(in millions)	2023		2022
Cost of removal obligations (1)	$	8,191	$	7,773
Public purpose programs (2)	1,238		1,062
Employee benefit plans (3)	1,032		904
Transmission tower wireless licenses (4)	384		430
SFGO sale (5)	185		264
SB 901 securitization (6)	6,628		5,800
Wildfire self-insurance (7)	407		—
Other	1,379		1,397
Total noncurrent regulatory liabilities	$	19,444	$	17,630

(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected through rates for expected costs to remove assets.

(2) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.

(3) Represents cumulative differences between incurred costs and amounts collected through rates for post-retirement medical, post-retirement life and long-term disability plans.

(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $384 million, $288 million will be refunded to FERC-jurisdictional customers through 2042, and $96 million will be refunded to CPUC-jurisdictional customers through 2026.

(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022.

(6) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception. See Note 5 below.

(7) Represents amounts collected through rates designated for wildfire self-insurance. See Note 14 below.

Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. In addition, certain regulatory balancing accounts earn interest which is reflected in Interest income in the Consolidated Statements of Income. Interest income from balancing accounts was $547 million, $153 million and $18 million for the years ended December 31, 2023, 2022, and 2021, respectively.

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


	Receivable Balance at December 31,
(in millions)	2023		2022
Electric distribution (1)	$	1,092	$	448
Electric transmission (2)	99		96
Gas distribution and transmission (3)	144		72
Energy procurement (4)	1,002		684
Public purpose programs (5)	137		358
Fire hazard prevention memorandum account (6)	40		—
Wildfire mitigation plan memorandum account (7)	161		—
Wildfire mitigation balancing account (8)	12		2
Vegetation management balancing account (9)	340		137
Insurance premium costs (10)	227		602
Residential uncollectibles balancing accounts (11)	507		126
Catastrophic event memorandum account (12)	413		144
General rate case memorandum accounts (13)	1,097		—
Other	389		595
Total regulatory balancing accounts receivable	$	5,660	$	3,264


	Payable Balance at December 31,
(in millions)	2023		2022
Electric transmission (2)	$	200	$	228
Gas distribution and transmission (3)	224		66
Energy procurement (4)	77		428
Public purpose programs (5)	299		272
SFGO sale	79		152
Wildfire mitigation balancing account (8)	125		—
Nuclear decommissioning adjustment mechanism (14)	216		8
Other	449		504
Total regulatory balancing accounts payable	$	1,669	$	1,658

(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.

(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases.

(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC rate case and other proceedings.

(4) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities.

(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.

(6) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards which were approved for cost recovery in the 2020 WMCE final decision.

(7) The WMPMA tracks costs associated with the 2019 WMP which were approved for cost recovery in the 2020 WMCE final decision.

(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities which were authorized for cost recovery in the 2021 WMCE proceeding and the final decision granting interim rate relief in connection with the 2022 WMCE application.

(9) The VMBA tracks routine and enhanced vegetation management activities which were approved for cost recovery in the final decision granting interim rate relief in connection with the 2022 WMCE application.

(10) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in noncurrent Regulatory assets above, as of December 31, 2023, and 2022 there were $0 and $48 million, respectively, in insurance premium costs recorded in current Regulatory assets.

(11) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. The RUBA balance increased from December 31, 2022 to December 31, 2023 due to additional under-collections from residential customers, which are expected to be recovered in 2024.

(12) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2018 CEMA and 2020 WMCE final decisions.

(13) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023.

(14) The Nuclear decommissioning adjustment mechanism (“NDAM”) account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision. See Note 2 above.

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 at December 31, 2023:


(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2028	$	4,400	(1)	$	(1,750)	$	(652)	$	1,998
Utility Receivables Securitization Program (2)	June 2025	1,499		(3)	(1,499)		—		—		(3)
PG&E Corporation revolving credit facility	June 2026	500			—		—		500
Total credit facilities		$	6,399		$	(3,249)	$	(652)	$	2,498

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

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

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

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

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

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

On November 15, 2023, the Utility entered into a Bridge Term Loan Credit Agreement (the “Bridge Term Loan Credit Agreement”), pursuant to which the lenders made available to the Utility term loans in the aggregate principal amount equal to $2.1 billion (the “Term Loans”). The Utility borrowed the entire amount of the Term Loans on November 15, 2023. The Term Loans have a maturity date of August 15, 2024. The Utility is required to prepay loans outstanding under the Bridge Term Loan Credit Agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance or incurrence of any debt by its subsidiary, Pacific Generation. Borrowings under the Bridge Term Loan Credit Agreement bear interest based on the Utility’s election of either (1) Term SOFR (as defined in the Bridge Term Loan Credit Agreement) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25% or (2) the alternate base rate plus an applicable margin of 0.25%.

PG&E Corporation

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

On December 8, 2023, PG&E Corporation entered into an amendment to its existing term loan agreement to, among other things, extend the maturity date from June 23, 2025 to June 23, 2027, and reduce the applicable margin from 300 basis points to 250 basis points. The term loan bears interest based on Adjusted Term SOFR plus an applicable margin of 2.50%.

On December 4, 2023, PG&E Corporation used the net proceeds from the Convertible Notes, together with cash on hand, to prepay $2.15 billion of aggregate principal amount of the term loans under the term loan agreement. See “Convertible Notes” below. In addition, on December 8, 2023, PG&E Corporation used other available funds to prepay $11 million of aggregate principal amount of the term loans under the term loan agreement. As a result of the early extinguishment of these term loans, PG&E Corporation recognized $26 million of unamortized discount and issuance costs in Interest expense in the Consolidated Financial Statements for the year ended December 31, 2023. The outstanding aggregate principal amount of term loans outstanding after giving effect to these prepayments and the amendment to the term loan agreement is $500 million.

Long-Term Debt Issuances and Redemptions

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

On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.700% First Mortgage Bonds due 2053. The Utility intends to disburse or allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing eligible green projects and eligible social projects. Pending full disbursement or allocation of an amount equal to the net proceeds from this offering to finance or refinance eligible projects, the Utility expects to use the net proceeds for the repayment of borrowings outstanding under the Utility Revolving Credit Agreement.

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

On November 8, 2023, the Utility completed the sale of $800 million aggregate principal amount of 6.950% First Mortgage Bonds due 2034. The Utility used the net proceeds to repay a portion of the $900 million aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 at maturity.

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”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $2.12 billion, after deducting the Initial Purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

The Convertible Notes are governed by an Indenture (the “Convertible Notes Indenture”) among PG&E Corporation, as the issuer, The Bank of New York Mellon Trust Company, N.A., as Trustee, and JPMorgan Chase Bank, N.A., as collateral agent. The Indenture governing the Convertible Notes contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity.

Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met:

during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;
during the five consecutive business day period immediately after any ten consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90% of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or
upon specified distributions and corporate events described in the Convertible Notes Indenture.

On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date.

On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion (as defined in the Convertible Notes Indenture) to Combination Settlement (as defined in the Convertible Notes Indenture) with a Specified Dollar Amount (as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000.

The conversion rate for the Convertible Notes is initially 43.1416 shares of Common Stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $23.18 per share of PG&E Corporation Common Stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date.

If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2023, none of the conditions allowing holders of the Convertible Notes to convert had been met.

The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options. Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470.

As of December 31, 2023, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.12 billion, with unamortized debt issuance costs of $27 million in Long-term debt. For the year ended December 31, 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $7 million.

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:


		Balance at
(in millions)	Contractual Interest Rates	December 31, 2023		December 31, 2022
PG&E Corporation
Term Loan - Stated Maturity: 2027 (1)	variable rate (2)	$	500	$	2,681
Convertible Notes due 2027	4.25%	2,150		—
Senior Secured Notes due 2028	5.00%	1,000		1,000
Senior Secured Notes due 2030	5.25%	1,000		1,000
Less: current portion, net of unamortized discount and debt issuance costs		—		(28)
Unamortized discount and debt issuance costs, net		(51)		(66)
Total PG&E Corporation Long-Term Debt		4,599		4,587
Utility
First Mortgage Bonds - Stated Maturity:
2023	1.70% - 4.25%	—		2,075
2024	3.40% - 3.75%	800		1,800
2025	3.45% - 4.95%	1,925		1,925
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 5.45%	3,000		3,000
2028	3.00% - 4.65%	1,975		1,975
2029	4.20% - 6.10%	1,250		400
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		3,000
2032	4.40% - 5.90%	1,050		1,050
2033	6.15% - 6.40%	1,900		—
2034	6.95%	800		—
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		700
2042	3.75% - 4.45%	750		750
2043	4.60%	375		375
2044	4.75%	675		675
2045	4.30%	600		600
2046	4.00% - 4.25%	1,050		1,050
2047	3.95%	850		850
2050	3.50% - 4.95%	5,025		5,025
2052	5.25%	550		550
2053	6.70% - 6.75%	2,000		—
Less: current portion, net of unamortized discount and debt issuance costs		(800)		(2,072)
Unamortized discount, premium and debt issuance costs, net		(246)		(195)
Total Utility First Mortgage Bonds		35,831		32,135
Recovery Bonds (3)		9,124		9,292
Less: current portion		(176)		(168)
DWR Loan (4)		98		312
Credit Facilities
Receivables Securitization Program - Stated Maturity: 2025	variable rate (5)	1,499		1,184
2-Year Term Loan - Stated Maturity: 2024	variable rate (6)	400		400
Less: current portion		(400)		—
Total Utility Long-Term Debt		46,376		43,155
Total PG&E Corporation Consolidated Long-Term Debt		$	50,975	$	47,742

(1) On December 8, 2023, PG&E Corporation amended its existing term loan agreement to, among other things, extend the maturity date from June 23, 2025 to June 23, 2027.

(2) At December 31, 2023, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.85% and at December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the term loan was 7.44%.

(3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K and 2022 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.

(4) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.

(5) At December 31, 2023 and 2022, the contractual SOFR-based interest rate on the Receivables Securitization Program was 6.75% and 5.10%, respectively.

(6) At December 31, 2023 and 2022, the contractual SOFR-based interest rate on the term loan was 6.60% and 5.71%, respectively.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2023 are reflected in the table below:



(in millions, except interest rates)	2024			2025			2026			2027			2028			Thereafter			Total
PG&E Corporation
Average fixed interest rate	—		%	—		%	—		%	4.25		%	5.00		%	5.25		%	4.67		%
Fixed rate obligations	$	—		$	—		$	—		$	2,150		$	1,000		$	1,000		$	4,150
Variable interest rate as of December 31, 2023	—		%	—		%	—		%	7.85		%	—		%	—		%	7.85		%
Variable rate obligations	$	—		$	—		$	—		$	500		$	—		$	—		$	500
Utility (1)
Average fixed interest rate	3.60		%	3.82		%	3.10		%	3.22		%	3.58		%	4.66		%	4.31		%
Fixed rate obligations	$	800		$	1,925		$	2,551		$	3,000		$	1,975		$	26,626		$	36,877
Variable interest rate as of December 31, 2023	6.60		%	6.75		%	—		%	—		%	—		%	—		%	6.72		%
Variable rate obligations	$	400		$	1,499		$	—		$	—		$	—		$	—		$	1,899
Recovery Bonds (2)
AB 1054 obligations	$	46		$	48		$	50		$	51		$	53		$	1,539		$	1,787
SB 901 obligations	130			135			141			146			152			6,634			7,338
Total consolidated debt	$	1,376		$	3,607		$	2,742		$	5,847		$	3,180		$	35,799		$	52,551

(1) The balance excludes DWR loan, see Note 2 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K and 2022 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.

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 CHT 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 11 below). The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Consolidated Statements of Income and had no net impact on Operating revenues for the year ended December 31, 2023.

Upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. Of the $2.0 billion in required upfront shareholder contributions, $1.0 billion was contributed to the customer credit trust in 2022, and $1.0 billion is required to be contributed in 2024. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust 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 Consolidated Statements of Income. During the year ended December 31, 2023, the Utility recorded SB 901 securitization charges, net, of $1.3 billion for tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (see Note 6 below) and $322 million for amortization of the regulatory asset and liability in the Consolidated Statements of Income. During the year ended December 31, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability as well as tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock and amortization of the regulatory asset and liability in the 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 since December 31, 2022:


SB 901 securitization regulatory asset (in millions)
Balance at December 31, 2022	$	5,378
Amortization	(129)
Balance at December 31, 2023	$	5,249


SB 901 securitization regulatory liability (in millions)
Balance at December 31, 2022	$	(5,800)
Amortization	451
Additions(1)	(1,279)
Balance at December 31, 2023	$	(6,628)

(1) Includes $12 million of expected returns on investments in the customer credit trust to be credited to customers.

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 2,133,597,758 shares of common stock outstanding at December 31, 2023, which excludes 477,743,590 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2023.

Settlement of Equity Units

During 2020, PG&E Corporation issued 16 million PG&E Corporation equity units. The equity units represent the right of the unit holders to receive, on the settlement date, between 137 million and 168 million shares of PG&E Corporation common stock. The common stock received was based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contract component of each equity unit and was subject to certain adjustments as provided therein. The common stock received by these unit holders was originally valued at approximately $1.3 billion and recognized in shareholders’ equity by PG&E Corporation upon the issuance of the equity units. During the year ended December 31, 2023, all equity units were settled, resulting in the issuance of 137 million shares of PG&E Corporation common stock, valued at approximately $1.3 billion.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these DTAs to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation.

Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. For example, although PG&E Corporation had 2,611,366,666 shares outstanding as of February 14, 2024, only 2,133,623,076 shares (that is, the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 14, 2024 was 3.88% of the outstanding shares. At various dates throughout 2022 and 2023, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 247,743,590 shares resulted in an aggregate tax benefit of $1.2 billion recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. Cumulatively through December 31, 2023, the Fire Victim Trust has sold all of its 477,743,590 shares resulting in an aggregate tax benefit of approximately $2.0 billion recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. As of February 14, 2024, the Fire Victim Trust reported having sold all of the shares of PG&E Corporation common stock it had owned and no longer owning any shares.

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

Dividends

On November 27, 2023, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, totaling $21 million, which was paid by January 16, 2024, to holders of record as of December 29, 2023.

On February 14, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, payable on April 15, 2024, to holders of record as of March 28, 2024.

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 the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant.

Long-Term Incentive Plans

The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 61,716,764 shares were available for future awards at December 31, 2023.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2023:


(in millions)	2023		2022		2021
Restricted stock units	64		60		35
Performance shares	27		55		21
Total compensation expense (pre-tax)	$	91	$	115	$	56
Total compensation expense (after-tax)	$	65	$	83	$	40

Share-based compensation costs are generally not capitalized. There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2023, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. No stock options were granted in 2023 or 2022.

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2023.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2023:


	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,152,132	$	7.36		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(755,871)	5.80			—
Outstanding at December 31	1,396,261	8.20		2.29	—
Vested or expected to vest at December 31	1,396,261	8.20		2.29	—
Exercisable at December 31	1,396,261	$	8.20	2.29	$	—

(1) Represents additional payout of existing stock option grants.

Restricted Stock Units

Restricted stock units generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2023, 2022, and 2021 was $15.70, $11.40, and $11.01, respectively. The total fair value of restricted stock units that vested during 2023, 2022, and 2021 was $64 million, $46 million, and $19 million, respectively. The tax detriment from restricted stock units that vested in 2023 was $26 million. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2023, $74 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.42 years.

The following table summarizes restricted stock unit activity for 2023:


	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	10,978,120	$	11.21
Granted	4,337,632	15.70
Vested	(5,710,073)	11.16
Forfeited	(337,254)	12.77
Nonvested at December 31	9,268,425	$	13.29

Performance Shares

Performance shares generally vest three years after the grant date. Following vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR). Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled.

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-based awards or the grant-date market value of PG&E Corporation common stock for awards based on internal metrics. The weighted average grant-date fair value for performance shares granted during 2023, 2022, and 2021 was $13.39, $13.44, and $11.83 respectively. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2023, $43 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.27 years.

The following table summarizes activity for performance shares in 2023:


	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	11,022,054	$	10.68
Granted	4,881,031	13.39
Vested	(8,049,294)	9.16
Forfeited	(1,251,499)	13.2
Nonvested at December 31	6,602,292	$	14.06

NOTE 7: PREFERRED STOCK

PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share. At December 31, 2023 and 2022, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share, respectively. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

At December 31, 2023, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2023, annual dividends on the Utility’s redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid $14 million of dividends on preferred stock in 2023. The Utility paid approximately $70 million of dividends on preferred stock in 2022, of which approximately $59 million was paid in arrears. In addition, on February 14, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on May 15, 2024, to holders of record as of April 30, 2024.

NOTE 8: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) 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 (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2023, 2022, and 2021.


	Year Ended December 31,
(in millions, except per share amounts)	2023		2022		2021
Income (loss) available for common shareholders	$	2,242	$	1,800	$	(102)
Weighted average common shares outstanding, basic	2,064		1,987		1,985
Add incremental shares from assumed conversions:
Employee share-based compensation	6		8		—
Equity Units	68		137		—
Weighted average common shares outstanding, diluted	2,138		2,132		1,985
Total earnings (loss) per common share, diluted	$	1.05	$	0.84	$	(0.05)

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, as a result of an irrevocable election made on December 8, 2023 to fix the settlement method to combination settlement, the Convertible Notes (as defined in Note 4) did not have a material impact on the calculation of diluted EPS.

NOTE 9: INCOME TAXES

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating DTAs and liabilities. DTAs and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the technical merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit.

Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:


	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2023		2022		2021		2023		2022		2021
Current:
Federal	$	(1)	$	(1)	$	—	$	(1)	$	(1)	$	—
State	—		—		1		—		—		—
Deferred:
Federal	(1,047)		(943)		543		(981)		(852)		588
State	(507)		(389)		296		(477)		(348)		316
Tax credits	(2)		(5)		(4)		(2)		(5)		(4)
Income tax provision (benefit)	$	(1,557)	$	(1,338)	$	836	$	(1,461)	$	(1,206)	$	900

The following tables describe net deferred income tax assets and liabilities:


	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2023		2022		2023		2022
Deferred income tax assets:
Tax carryforwards	$	9,132	$	7,156	$	8,740	$	6,868
Compensation	145		157		82		80
GHG allowance	361		239		361		239
Wildfire-related claims (1)	1,069		1,489		1,069		1,489
Operating lease liability	142		368		142		368
Transmission tower wireless licenses	250		254		250		254
Bad debt	134		55		134		55
Other (2)	130		142		109		122
Total deferred income tax assets	$	11,363	$	9,860	$	10,887	$	9,475
Deferred income tax liabilities:
Property-related basis differences	10,058		9,374		10,047		9,363
Regulatory balancing accounts	1,433		1,376		1,433		1,376
Debt financing costs	428		465		428		465
Operating lease ROU asset	142		368		142		368
Income tax regulatory asset (3)	991		764		991		764
Environmental reserve	200		163		200		163
Other (4)	91		82		82		67
Total deferred income tax liabilities	$	13,343	$	12,592	$	13,323	$	12,566
Total net deferred income tax liabilities	$	1,980	$	2,732	$	2,436	$	3,091

(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred in PG&E Corporation’s and the Utility’s service area over the past several years.

(2) Amounts include benefits, state taxes, and customer advances for construction.

(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the TCJA.

(4) Amounts primarily include property taxes and prepaid expense.

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


	PG&E Corporation						Utility
	Year Ended December 31,
	2023		2022		2021		2023		2022		2021
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(57.9)		(75.8)		31.3		(34.4)		(26.9)		24.1
Effect of regulatory treatment of fixed asset differences (2)	(63.4)		(123.8)		(71.5)		(40.1)		(49.2)		(51.6)
Tax credits	(2.2)		(3.2)		(1.7)		(2.2)		(1.3)		(1.2)
Fire Victim Trust (3)	(126.9)		(160.9)		127.3		(80.2)		(64.0)		91.9
Other, net (4)	2.2		12.9		5.3		1.1		2.2		2.6
Effective tax rate	(227.2)	%	(329.8)	%	111.7	%	(134.8)	%	(118.2)	%	86.8	%

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

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2023, 2022, and 2021, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA passed in December 2017.

(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023 and 2022 and a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:


	PG&E Corporation						Utility
(in millions)	2023		2022		2021		2023		2022		2021
Balance at beginning of year	$	570	$	498	$	437	$	570	$	498	$	437
Additions for tax position taken during a prior year	1		—		—		1		—		—
Reductions for tax position taken during a prior year	—		(1)		(23)		—		(1)		(23)
Additions for tax position taken during the current year	45		73		85		45		73		85
Settlements	—		—		(1)		—		—		(1)
Balance at end of year	$	616	$	570	$	498	$	616	$	570	$	498

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2023 for PG&E Corporation and the Utility was $33 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months based on tax audit progress.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2023, 2022, and 2021, these amounts were immaterial.

Tax Audits

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

PG&E Corporation’s tax returns have been accepted through 2014 for California income tax purposes. Tax years 2015 and thereafter remain subject to examination by the State of California. The State of California is auditing tax years 2015 through 2019.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:


(in millions)	December 31, 2023		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,447	2031 - 2036
Net operating loss carryforward - Post-2017	29,403		N/A
Tax credit carryforward	175		2029 - 2041

State:
Net operating loss carryforward	$	32,583	2039 - 2041
Tax credit carryforward	137		Various

PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards.

Other Tax Matters

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation’s or the Utility’s ability to use these DTAs to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). The Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”).

Furthermore, due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation recognized income tax benefits and the corresponding DTA as the Fire Victim Trust sold shares of PG&E Corporation common stock, and the amounts of such benefits and assets were determined largely by the price at which the Fire Victim Trust sold the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. From inception through December 31, 2023, the Fire Victim Trust exchanged Plan Shares in the aggregate amount of 477,743,590 for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. In the year ended December 31, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 247,743,590 shares resulted in an aggregate tax benefit of $1.2 billion recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. For more information, see Note 6 above.

NOTE 10: 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 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 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 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 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	December 31, 2023	December 31, 2022
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	196,063,296	171,212,813
	Options	30,695,000	27,785,000
Electricity (MWh)	Forwards, Futures and Swaps	9,169,967	10,814,728
	Options	92,400	215,600
	Congestion Revenue Rights (3)	170,465,674	205,743,505

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

(2) Million British Thermal Units.

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

Presentation of Derivative Instruments in the Financial Statements

As of 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

As of December 31, 2022, 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	$	824	$	(170)	$	537	$	1,191
Other noncurrent assets – other	306		—		—		306
Current liabilities – other	(238)		170		16		(52)
Noncurrent liabilities – other	(177)		—		—		(177)
Total commodity risk	$	715	$	—	$	553	$	1,268

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s 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 December 31, 2023, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 11: 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 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 10)
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 10)
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.


	Fair Value Measurements
	December 31, 2022
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	658	$	—	$	—	$	—	$	658
Fixed-income securities	—		49		—		—		49
Nuclear decommissioning trusts
Short-term investments	117		—		—		—		117
Global equity securities	1,845		—		—		—		1,845
Fixed-income securities	1,094		791		—		—		1,885
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,056		791		—		—		3,872
Customer credit trust
Short-term investments	19		—		—		—		19
Global equity securities	218		—		—		—		218
Fixed-income securities	216		292		—		—		508
Total customer credit trust	453		292		—		—		745
Price risk management instruments (Note 10)
Electricity	—		94		432		40		566
Gas	—		604		—		327		931
Total price risk management instruments	—		698		432		367		1,497
Rabbi trusts
Short-term investments	25		—		—		—		25
Global equity securities	5		—		—		—		5
Fixed-income securities	—		69		—		—		69
Life insurance contracts	—		64		—		—		64
Total rabbi trusts	30		133		—		—		163
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		133
Total long-term disability trust	10		—		—		—		143
TOTAL ASSETS	$	4,207	$	1,963	$	432	$	367	$	7,127
Liabilities:
Price risk management instruments (Note 10)
Electricity	$	—	$	10	$	233	$	(20)	$	223
Gas	—		172		—		(166)		6
TOTAL LIABILITIES	$	—	$	182	$	233	$	(186)	$	229

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

(2) Represents amount before deducting $575 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2023 and 2022.

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 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 10 above.


	Fair Value at
(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.


	Fair Value at
(in millions)	At December 31, 2022				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities			Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	305	$	138	Market approach	CRR auction prices	$ (145.09) - 2,724.93 / 0.89
Power purchase agreements	$	127	$	95	Discounted cash flow	Forward prices	$ (6.39) - 286.75 / 78.14

(1) Represents price per MWh.

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

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2023 and 2022, respectively:


	Price Risk Management Instruments
(in millions)	2023		2022
Asset (Liability) balance as of January 1	$	199	$	(34)
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(8)		233
Asset balance as of December 31	$	191	$	199

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

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values as of December 31, 2023 and December 31, 2022, 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 December 31, 2023				At December 31, 2022
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	4,548	$	4,695	$	4,355	$	4,490
Utility	35,909		32,866		32,847		27,666

(1) As of December 31, 2023, 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 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
As of December 31, 2022
Nuclear decommissioning trusts
Short-term investments	$	117	$	—	$	—	$	117
Global equity securities	413		1,468		(11)		1,870
Fixed-income securities	1,991		10		(116)		1,885
Total (1)	$	2,521	$	1,478	$	(127)	$	3,872

(1) Represents amounts before deducting $717 million and $575 million as of December 31, 2023 and December 31, 2022, respectively, primarily related to deferred taxes on appreciation of investment value.

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


	As of
(in millions)	December 31, 2023
Less than 1 year	$	9
1–5 years	665
5–10 years	463
More than 10 years	940
Total maturities of fixed-income securities	$	2,077

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


(in millions)	2023		2022		2021
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	2,235	$	3,316	$	1,678
Gross realized gains on securities	80		2		286
Gross realized losses on securities	(74)		(3)		(19)

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 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
As of December 31, 2022
Customer credit trust
Short-term investments	$	19	$	—	$	—	$	19
Global equity securities	219		13		(14)		218
Fixed-income securities	516		—		(8)		508
Total	$	754	$	13	$	(22)	$	745

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


	As of
(in millions)	December 31, 2023
Less than 1 year	$	—
1–5 years	25
5–10 years	29
More than 10 years	59
Total maturities of fixed-income securities	$	113

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


(in millions)	2023		2022
Proceeds from sales and maturities of customer credit trust investments	$	556	$	250
Gross realized gains on securities	23		10
Gross realized losses on securities (1)	(19)		(41)

(1) Includes $4 million and $6 million of impaired debt securities which were written down to their respective fair values during the year ended December 31, 2023 and the year ended December 31, 2022, respectively.

NOTE 12: EMPLOYEE BENEFIT PLANS

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). Certain trusts underlying these plans are qualified trusts under the IRC. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. On an annual basis, the Utility funds the pension plan up to the amount it is authorized to recover through rates.

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2023 and 2022:

Pension Plan


(in millions)	2023		2022
Change in plan assets:
Fair value of plan assets at beginning of year	$	16,369	$	21,895
Actual return on plan assets	1,518		(4,916)
Company contributions	336		339
Benefits and expenses paid	(1,012)		(949)
Fair value of plan assets at end of year	$	17,211	$	16,369

Change in benefit obligation:
Benefit obligation at beginning of year	$	16,608	$	22,759
Service cost for benefits earned	379		575
Interest cost	913		692
Actuarial loss (gain) (1)	809		(6,471)
Plan amendments	—		—
Benefits and expenses paid	(1,012)		(947)
Benefit obligation at end of year (2)	$	17,697	$	16,608

Funded Status:
Current liability	$	(9)	$	(8)
Noncurrent liability	(477)		(231)
Net liability at end of year	$	(486)	$	(239)

(1) The actuarial loss for the year ended December 31, 2023 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in the demographic assumptions; the actuarial gain for the year ended December 31, 2022 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions.

(2) PG&E Corporation’s accumulated benefit obligation was $16.3 billion and $15.4 billion at December 31, 2023 and 2022, respectively.

Postretirement Benefits Other than Pensions


(in millions)	2023		2022
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,336	$	3,102
Actual return on plan assets	260		(693)
Company contributions	5		26
Plan participant contribution	81		81
Benefits and expenses paid	(183)		(180)
Fair value of plan assets at end of year	$	2,499	$	2,336

Change in benefit obligation:
Benefit obligation at beginning of year	$	1,339	$	1,766
Service cost for benefits earned	38		62
Interest cost	73		53
Actuarial loss (gain) (1)	8		(486)
Benefits and expenses paid	(165)		(162)
Federal subsidy on benefits paid	3		3
Plan participant contributions	81		81
Voluntary separation program-related termination benefits (2)	—		22
Benefit obligation at end of year	$	1,377	$	1,339

Funded Status: (3)
Noncurrent asset	$	1,122	$	997
Noncurrent liability	—		—
Net asset at end of year	$	1,122	$	997

(1) The actuarial loss for the year ended December 31, 2023 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations, offset by favorable changes in claims cost and demographic assumptions. The actuarial gain for the year ended December 31, 2022 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations, offset by unfavorable changes in demographic assumptions.

(2) Represents voluntary separation program related credits to employee retirement health savings accounts. See “Voluntary Separation Program” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K.

(3) At December 31, 2023 and 2022, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $275 million and $292 million as of December 31, 2023, and $259 million and $266 million as of December 31, 2022, respectively.

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

Components of Net Periodic Benefit Cost

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.

Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows:

Pension Plan


(in millions)	2023		2022		2021
Service cost for benefits earned (1)	$	379	$	575	$	587
Interest cost	913		692		645
Expected return on plan assets	(981)		(1,189)		(1,046)
Amortization of prior service cost	(4)		(4)		(6)
Amortization of net actuarial loss	1		2		6
Net periodic benefit cost	308		76		186
Less: transfer to regulatory account (2)	25		254		147
Total expense recognized	$	333	$	330	$	333

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions


(in millions)	2023		2022		2021
Service cost for benefits earned (1)	$	38	$	62	$	63
Interest cost	73		53		51
Expected return on plan assets	(132)		(130)		(137)
Amortization of prior service cost	3		7		14
Amortization of net actuarial gain	(19)		(40)		(33)
Special termination benefits	—		22		—
Net periodic benefit cost	$	(37)	$	(26)	$	(42)

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

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

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

Components of Accumulated Other Comprehensive Income

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

Valuation Assumptions

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.


	Pension Plan						PBOP Plans
	December 31,						December 31,
	2023		2022		2021		2023	2022	2021
Discount rate	5.21	%	5.54	%	3.03	%	5.18 - 5.22%	5.50 - 5.54%	2.97 - 3.04%
Rate of future compensation increases	3.80	%	3.80	%	3.80	%	N/A	N/A	N/A
Expected return on plan assets	6.00	%	6.10	%	5.50	%	3.70 - 7.00%	3.70 - 7.30%	3.30 - 6.40%
Interest crediting rate for cash balance plan	3.86	%	4.19	%	1.95	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2023 was 6.25%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 and beyond.

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 6.0% compares to a ten-year actual return of 5.3%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 858 Aa-grade non-callable bonds at December 31, 2023. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios.

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the allocation between fixed income and equity of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non-U.S. dollar exposure of global equity investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:


	Pension Plan						PBOP Plans
	2024		2023		2022		2024		2023		2022
Global equity securities	26	%	26	%	30	%	29	%	28	%	26	%
Absolute return	1	%	1	%	2	%	—	%	1	%	1	%
Real assets	8	%	8	%	8	%	3	%	3	%	3	%
Fixed-income securities	65	%	65	%	60	%	68	%	68	%	70	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2023 and 2022.


	Fair Value Measurements
	At December 31,
	2023								2022
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	565	$	86	$	—	$	651	$	461	$	126	$	—	$	587
Global equity securities	1,270		—		—		1,270		1,430		—		—		1,430
Real assets	472		—		—		472		426		—		—		426
Fixed-income securities	1,926		6,802		13		8,741		1,946		6,086		8		8,040
Assets measured at NAV	—		—		—		6,080		—		—		—		5,886
Total	$	4,233	$	6,888	$	13	$	17,214	$	4,263	$	6,212	$	8	$	16,369
PBOP Plans:
Short-term investments	$	30	$	—	$	—	$	30	$	26	$	—	$	—	$	26
Global equity securities	66		—		—		66		83		—		—		83
Real assets	32		—		—		32		29		—		—		29
Fixed-income securities	422		795		1		1,218		406		702		1		1,109
Assets measured at NAV	—		—		—		1,160		—		—		—		1,100
Total	$	550	$	795	$	1	$	2,506	$	544	$	702	$	1	$	2,347
Total plan assets at fair value							$	19,720							$	18,716

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $10 million and $11 million at December 31, 2023 and 2022, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a NAV per share can be redeemed quarterly with a notice not to exceed 90 days.

Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity Securities

The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Real Assets

The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.

Fixed-Income Securities

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 debt 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 trusts 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 Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2023 or 2022.

Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2023 and 2022:


(in millions)
For the year ended December 31, 2023	Fixed-Income
Balance at beginning of year	$	8
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(1)
Purchases, issuances, sales, and settlements:
Purchases	10
Settlements	(6)
Balance at end of year	$	13

(in millions)
For the year ended December 31, 2022	Fixed-Income
Balance at beginning of year	$	27
Actual return on plan assets:
Relating to assets still held at the reporting date	1
Relating to assets sold during the period	—
Purchases, issuances, sales, and settlements:
Purchases	6
Settlements	(26)
Balance at end of year	$	8

There were no material transfers out of Level 3 in 2023 or 2022.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $336 million to the pension benefit plans, $31 million to the long-term disability trusts, and $5 million to the other postretirement benefit plans in 2023. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. The Utility’s pension benefits met all the funding requirements under the Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the pension plan in 2024. PG&E Corporation and the Utility plan to contribute $31 million to the long-term disability trusts in 2024, as authorized in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2023, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:


(in millions)	Pension Plan	PBOP Plans	Federal Subsidy
2024	957	93	(4)
2025	1,040	93	(1)
2026	1,066	96	(1)
2027	1,089	87	(1)
2028	1,111	89	(1)
Thereafter in the succeeding five years	5,802	471	(4)

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the IRC. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan and provides for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $158 million, $144 million, and $133 million in 2023, 2022, and 2021, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were:


	Year Ended December 31,
(in millions)	2023		2022		2021
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	3
Utility expenses from:
Administrative services received from PG&E Corporation	$	80	$	104	$	82
Utility employee benefit due to PG&E Corporation	74		85		39

At December 31, 2023 and 2022, the Utility had receivables of $26 million and $33 million, respectively, from PG&E Corporation included in Accounts receivable – other and Noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $24 million and $46 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

NOTE 14: 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 charges PG&E Corporation and the Utility have paid through December 31, 2023.


Payments (in millions)
2019 Kincade Fire	$	667
2020 Zogg Fire	390
2021 Dixie Fire	731
2022 Mosquito Fire	15
Total at December 31, 2023	$	1,803

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 February 14, 2024, PG&E Corporation and the Utility are aware of approximately 132 complaints on behalf of at least 2,913 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 28, 2023, the court scheduled a new trial date for August 26, 2024. 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 July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022.

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

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.025 billion as of December 31, 2022 (before available insurance). 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 an additional charge in the fourth quarter of 2023 for probable losses in connection with the 2019 Kincade fire of $100 million for an aggregate liability of $1.125 billion (before available insurance).

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, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022	$	650
Accrued Losses	100
Payments	(292)
Balance at December 31, 2023	$	458

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.

2020 Zogg Fire

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

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

As of February 14, 2024, PG&E Corporation and the Utility have settled or reached settlements in principle with substantially all individual plaintiffs.

On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect.

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

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

The following table presents changes in the best estimate of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022	$	32
Accrued Losses	—
Payments	(22)
Balance at December 31, 2023	$	10

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of December 31, 2023, the Utility recorded an insurance receivable for $374 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $34 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa.

2021 Dixie Fire

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

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 Consolidated Financial Statements as of December 31, 2023. For the recordkeeping initiative costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

As of February 14, 2024, PG&E Corporation and the Utility are aware of approximately 161 complaints on behalf of at least 8,387 individual plaintiffs and a separate putative class complaint related to the 2021 Dixie fire and expect that they may receive further complaints. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. On September 20, 2023, the court vacated the November 8, 2023 trial date and scheduled a new trial date for April 2, 2024. On June 30, 2023, Cal Fire also filed a complaint largely repeating the allegations of the earlier Cal Fire Investigation Report and seeking damages for fire suppression and investigation costs.

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

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

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

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, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022	$	1,131
Accrued Losses	425
Payments	(686)
Balance at December 31, 2023	$	870

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $900 million. Recovery under the Utility’s wildfire insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount up to $600 million and vice versa. As of December 31, 2023, the Utility recorded an insurance receivable of $526 million for probable insurance recoveries in connection with the 2021 Dixie fire, which equals the aggregate $900 million of available insurance coverage for third-party liability attributable to the 2021 Dixie fire, less the $374 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2023, the Utility recorded a Wildfire Fund receivable of $600 million for probable recoveries in connection with the 2021 Dixie fire. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund under AB 1054” below. As of December 31, 2023, the Utility also recorded a $91 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 $470 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 (“DOJ”), 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 preliminary, and PG&E Corporation and the Utility do not currently have access to the evidence in the possession of the USFS, the DOJ, or other third parties.

The CPUC 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 February 14, 2024, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 233 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency, a complaint on behalf of the Middle Fork Project Finance Authority, a complaint on behalf of El Dorado County, Placer County, Georgetown Divide Public Utility District, Georgetown Fire Protection District, and El Dorado County Water Agency. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

On November 13, 2023, PG&E Corporation and the Utility entered into an agreement with the insurance subrogation plaintiffs in the 2022 Mosquito fire litigation to resolve their claims arising from the 2022 Mosquito fire.

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, 2022.


Loss Accrual (in millions)
Balance at December 31, 2022	$	99
Accrued Losses	—
Payments	(14)
Balance at December 31, 2023	$	85

The Utility has liability insurance coverage for third-party liability in an aggregate amount of $733 million, with a deductible of $60 million. As of December 31, 2023, the Utility recorded an insurance receivable of $63 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including legal fees. As of December 31, 2023, the Utility also recorded a $8 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 $52 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

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

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2023 are:


Potential Recovery Source (in millions)	2022 Mosquito fire		2021 Dixie fire
Insurance	$	63	$	526
FERC TO rates	8		91
WEMA	52		470
Wildfire Fund	—		600
Probable recoveries at December 31, 2023 (1)	$	123	$	1,687

(1) Includes legal costs of $23 million and $82 million related to the 2022 Mosquito fire and 2021 Dixie fire, respectively, as of December 31, 2023.

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

Insurance

Insurance Coverage

In April 2022, the Utility purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million. In the year ended December 31, 2023, the Utility commuted $207 million of the $340 million in wildfire liability insurance coverage running from $757 million to $970 million. PG&E Corporation and the Utility did not procure additional wildfire liability insurance in 2023 as they moved to a program of self-insurance. See “Self-Insurance” below.

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

As of December 31, 2023, PG&E Corporation and the Utility had prepaid non-wildfire insurance of $61 million, reflected in Other current assets on the Consolidated Balance Sheets.

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

Self-Insurance

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance is entirely based on self-insurance once all of the Utility’s existing wildfire liability insurance policies expire, which occurred on August 1, 2023. The self-insurance is funded through CPUC-jurisdictional rates at $400 million for test year 2023, with billings and collections commencing in March 2023, and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected through rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. The settlement agreement includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market. Additionally, the Utility will recover approximately $100 million of funding through FERC-jurisdictional rates in each of 2024 and 2025.

As of December 31, 2023, the Utility had contributed $340 million to its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance, of which $8 million was classified as Restricted cash due to minimum capital and surplus requirements.

Insurance Receivable

Through December 31, 2023, PG&E Corporation and the Utility recorded $430 million, $374 million, $526 million, and $63 million for probable insurance recoveries in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:


Insurance Receivable (in millions)	2022 Mosquito fire		2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		Total
Balance at December 31, 2022	$	45	$	530	$	118	$	101	$	794
Accrued insurance recoveries (1)	18		(4)		4		—		18
Reimbursements	—		(200)		(75)		(101)		(376)
Balance at December 31, 2023	$	63	$	326	$	47	$	—	$	436

(1) For the year ended December 31, 2023, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $4 million.

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the [Utility’s] conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this 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 December 31, 2023, the Utility recorded reductions of $91 million and $8 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 December 31, 2023, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $470 million and $52 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 December 31, 2023 reflects an expectation that the Coverage Year will be based on the calendar year.

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

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On 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 of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating electric IOUs for a 10-year period.

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 December 31, 2023, PG&E Corporation and the Utility recorded $325 million and $275 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 and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, current and former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

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

Wildfire-Related Securities Claims in District Court

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

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

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

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

A group of shareholders who also filed proofs of claim in the Chapter 11 Cases filed a motion to intervene in the District Court action to, among other things, oppose the lifting of the stay sought by PERA. That motion remains pending. In addition, on March 21, 2023, a sub-set of this group of shareholders filed a separate action in the 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 action.

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

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

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, these defenses may not prevail and 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 July 2, 2020, PERA filed a notice of appeal of the order confirming the Plan, dated as of June 20, 2020 (the “Confirmation Order”), to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On August 10, 2021, the District Court issued an order affirming the Bankruptcy Court’s ruling with respect to the Insurance Deduction. On September 9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit. The Ninth Circuit Court of Appeals heard oral argument on May 5, 2023. On May 16, 2023, the Ninth Circuit Court of Appeals issued its decision affirming the District Court’s order. The time for appeal has expired.

On 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 15: 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 February 8, 2024, the Utility and certain intervenors reached a settlement in principle.

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.

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 fourth quarter of 2023 of approximately $484 million pending a final and non-appealable TO18 decision. Based on the settlement in principle, 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 December 31, 2023, 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 June 23, 2023, the ALJ revised the procedural schedule to indicate that a PD would be issued by the second quarter of 2024.

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 $89 million and $69 million as of December 31, 2023 and December 31, 2022, respectively. These amounts were included in Other current liabilities on the 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 14. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

PSPS Class Action

On December 19, 2019, a complaint was filed in the Bankruptcy Court naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid.

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

The plaintiff appealed the decision dismissing the complaint to the District Court. On March 26, 2021, the District Court affirmed the Bankruptcy Court’s dismissal of this action, and the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On November 20, 2023, the California Supreme Court ruled in favor of PG&E Corporation and the Utility, finding that the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. As a result, the plaintiff’s claims have since been dismissed.

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 Consolidated Balance Sheets and is comprised of the following:


	Balance at
(in millions)	December 31, 2023		December 31, 2022
Topock natural gas compressor station	$	276	$	284
Hinkley natural gas compressor station	104		110
Former MGP sites owned by the Utility or third parties (1)	809		750
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	107		112
Fossil fuel-fired generation facilities and sites (3)	19		26
Total environmental remediation liability	$	1,315	$	1,282

(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 EPA 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 December 31, 2023, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. As of December 31, 2023, 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 $216 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 $128 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. It is reasonably possible that the Utility’s undiscounted future costs associated with MGP sites may increase by as much as $579 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 $82 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 $43 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, a mutual insurer owned by utilities with nuclear facilities, 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 Humboldt Bay independent spent fuel storage installation, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL 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. NEIL also provides coverage for damages caused by cyber events at nuclear power plants. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI. EMANI shares losses with NEIL as part of the first $400 million in coverage for nuclear or non-nuclear property damages at Diablo Canyon. Additional coverage is procured through EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. The excess insurance coverage through EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. The coverage procured through EMANI also includes protection for acts of terrorism.

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $16.3 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $16.3 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $332 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $49 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $450 million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, covering liabilities in excess of the $53 million in liability insurance.

Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2023:


	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Natural Gas		Other (1)		Total
2024	$	2,005	$	481	$	584	$	301	$	3,371
2025	1,995		819		171		202		3,187
2026	1,935		766		123		275		3,099
2027	1,883		682		53		132		2,750
2028	1,827		683		—		41		2,552
Thereafter	15,676		1,501		—		9		17,186
Total purchase commitments	$	25,321	$	4,932	$	931	$	960	$	32,145

(1) Includes other power purchase agreements and nuclear fuel agreements.

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, qualifying facilities (“QF”) agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements

In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. These renewable energy contracts expire at various dates between 2024 and 2043.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and RA agreements. The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2024 and 2041.

Other Power Purchase Agreements

The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2023, QF contracts in operation expire at various dates between 2024 and 2041. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity were $2.4 billion in 2023, $2.8 billion in 2022, and $3.0 billion in 2021.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the United States Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2024 and 2041. In addition, the Utility has contracted for natural gas storage services in Northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, were $2.5 billion in 2023, $2.4 billion in 2022, and $1.2 billion in 2021.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2024 and 2029 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

Payments for nuclear fuel were $180 million in 2023, $44 million in 2022, and $79 million in 2021.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2024 and 2057. At December 31, 2023, the future minimum payments related to these commitments were as follows:


(in millions)	Other Commitments
2024	$	55
2025	29
2026	2
2027	—
2028	—
Thereafter	—
Total minimum lease payments	$	86

Payments for other commitments were $106 million in 2023, $63 million in 2022, and $50 million in 2021. Certain office facility leases contain escalation clauses requiring annual increases in rent. The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index. There are options to extend these leases for one to five years.

In addition to the commitments in the table above, pursuant to SB 901, a shareholder contribution to the customer credit trust of $1.0 billion is to be made in 2024. If the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution of up to $775 million in 2040.

Additionally, the Utility agreed to purchase the Lakeside Building for $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million to be paid on or before July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. See “Oakland Headquarters Lease and Purchase” in Note 2, above.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of PG&E Corporation and the Utility is responsible for establishing and maintaining adequate internal control over financial reporting. PG&E Corporation’s and the Utility’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2023, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2023.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of PG&E Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, equity and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current‐period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Regulation and Regulated Operations—Refer to Notes 2, 3 and 14 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company, follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utility Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. Pacific Gas & Electric Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for nonregulated entities. Pacific Gas & Electric Company capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.

We identified the impact of rate regulation, specifically costs that are subject to cost recovery proceedings that have not yet been approved, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the significant degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a significant degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost‐based rate regulation related to the uncertainty of future decisions by the rate regulators included the following, among others:

We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery of costs deferred as regulatory assets in future rates; and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.
We read relevant regulatory orders issued by the CPUC and FERC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.
We inspected the Utility’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact the Utility’s future rates, for any evidence that might contradict management’s assertions.
For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.
We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies and Recoveries—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Company has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire, 2021 Dixie fire and 2022 Mosquito fire as of December 31, 2023. The loss contingencies represent the lower end of the range of reasonably possible losses in connection with each of the fires, with the exception of the Zogg fire which represents the Company’s best estimate. The Company has also recorded estimated recoveries, inclusive of the Wildfire Expense Memorandum Account (“WEMA”), included within Noncurrent Regulatory Assets, and the Wildfire Fund Receivable, included within Accounts Receivable-Other and Other Noncurrent Assets.

We identified wildfire-related contingencies and related-recoveries, specifically the WEMA and Wildfire Fund Receivable, as well as the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses, (2) the outcome of the wildfire-related contingencies materially affects the Company’s financial position, results of operations, and cash flows and (3) the significant judgments made by management in determining whether recoveries from WEMA and the Wildfire Fund are probable. This required the application of a significant degree of auditor judgment and audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses, related recoveries, and disclosures.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire‐related contingencies, related recoveries, and disclosures included the following, among others:

We tested the effectiveness of controls over (1) the Company’s determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss, if any, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.
We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires and whether recoveries are probable, by inquiring of management and the Company’s legal counsel regarding the amount of probable and/or reasonably possible losses for each fire and each related recovery, including the potential impact of information gained through investigations into the cause of each fire, information from claimants, communication with insurers, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.
We obtained an analysis from management and external legal counsel for recoveries specific to WEMA, regarding probability of recovery for deferred costs not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery. We evaluated the Company’s conclusions regarding probability of recoverability of WEMA and from the Wildfire Fund, under accounting principles generally accepted in the United States of America.
We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness of the data sources utilized to determine the assumption utilized in management’s estimate.
We read the legal letters from the Company’s external and internal legal counsel regarding known information, and evaluated whether the information therein was consistent with the information obtained in our procedures.
We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained from our procedures performed.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2024

We have served as the Company’s auditor since 1999.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Pacific Gas and Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Utility as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Utility’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2024, expressed an unqualified opinion on the Utility’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Utility’s management. Our responsibility is to express an opinion on the Utility’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Critical Audit Matters

Regulation and Regulated Operations—Refer to Notes 2, 3 and 14 to the financial statements

Critical Audit Matter Description

The Utility follows accounting principles for rate‐regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utilities Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates and records regulatory liabilities for amounts that are likely to be refunded to customers. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

How the Critical Audit Matter Was Addressed in the Audit

We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery costs deferred as regulatory assets in future rates; and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.
We read relevant regulatory orders issued by the CPUC and FERC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.
We inspected the Utility’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact the Utility’s future rates, for any evidence that might contradict management’s assertions.
For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.
We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies and Recoveries—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire, 2021 Dixie fire and 2022 Mosquito fire as of December 31, 2023. The loss contingencies represent the lower end of the range of reasonably possible losses in connection with each of the fires, with the exception of the Zogg fire, which represents the Utility’s best estimate as of December 31, 2023. The Utility has also recorded estimated recoveries, inclusive of the Wildfire Expense Memorandum Account (“WEMA”), included within Noncurrent Regulatory Assets, and the Wildfire Fund Receivable, included within Accounts Receivable-Other and Other Noncurrent Assets.

We identified wildfire‐related contingencies and related‐recoveries, specifically the WEMA and Wildfire Fund, as well as the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses, (2) the outcome of the wildfire‐related contingencies materially affects the Utility’s financial position, results of operations, and cash flows and (3) the significant judgments made by management in determining whether recoveries from WEMA and the Wildfire Fund are probable. This required the application of a significant degree of auditor judgment and audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses, related recoveries, and disclosures.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire‐related contingencies, related recoveries, and disclosures included the following, among others:

We tested the effectiveness of controls over (1) the Utility’s determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss, if any, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.
We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires and whether recoveries are probable, by inquiring of management and the Utility’s legal counsel regarding the amount of probable and/or reasonably possible losses for each fire and each related recovery, including the potential impact of information gained through investigations into the cause of each fire, information from claimants, communication with insurers, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.
We obtained an analysis from management and external legal counsel for recoveries specific to WEMA, regarding probability of recovery for deferred costs not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery. We evaluated the Utility’s conclusions regarding probability of recoverability of WEMA and from the Wildfire Fund, under accounting principles generally accepted in the United States of America.
We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness of the data sources utilized to determine the assumption utilized in management’s estimate.
We read the legal letters from the Utility’s external and internal legal counsel regarding known information, and evaluated whether the information therein was consistent with the information obtained in our procedures.
We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained from our procedures performed.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2024

We have served as the Utility’s auditor since 1999.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of PG&E Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 21, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2024

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Pacific Gas and Electric Company

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Utility and our report dated February 21, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Utility’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Utility’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Definition and Limitations of Internal Control over Financial Reporting

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 21, 2024

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