Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

			Year ended December 31,
			2022						2021						2020
Operating Revenues
Electric			$	15,060					$	15,131					$	13,858
Natural gas			6,620						5,511						4,611
Total operating revenues			21,680						20,642						18,469
Operating Expenses
Cost of electricity			2,756						3,232						3,116
Cost of natural gas			2,100						1,149						782
Operating and maintenance			9,809						10,200						8,684
SB 901 securitization charges, net			608						—						—
Wildfire-related claims, net of recoveries			237						258						251
Wildfire Fund expense			477						517						413
Depreciation, amortization, and decommissioning			3,856						3,403						3,468
Total operating expenses			19,843						18,759						16,714
Operating Income			1,837						1,883						1,755
Interest income			162						20						39
Interest expense			(1,917)						(1,601)						(1,260)
Other income, net			394						457						483
Reorganization items, net			—						(11)						(1,959)
Income Before Income Taxes			476						748						(942)
Income tax provision (benefit)			(1,338)						836						362
Net Income (Loss)			1,814						(88)						(1,304)
Preferred stock dividend requirement of subsidiary			14						14						14
Income (Loss) Attributable to Common Shareholders			$	1,800					$	(102)					$	(1,318)
Weighted Average Common Shares Outstanding, Basic			1,987						1,985						1,257
Weighted Average Common Shares Outstanding, Diluted			2,132						1,985						1,257
Net Income (Loss) Per Common Share, Basic			$	0.91					$	(0.05)					$	(1.05)
Net Income (Loss) Per Common Share, Diluted			$	0.84					$	(0.05)					$	(1.05)

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

			Year ended December 31,
			2022						2021						2020
Net Income (Loss)			$	1,814					$	(88)					$	(1,304)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)			21						7						(17)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)			(6)						—						—
Total other comprehensive income (loss)			15						7						(17)
Comprehensive Income (Loss)			1,829						(81)						(1,321)
Preferred stock dividend requirement of subsidiary			14						14						14
Comprehensive Income (Loss) Attributable to Common Shareholders			$	1,815					$	(95)					$	(1,335)

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

			Balance at December 31,
			2022						2021
ASSETS
Current Assets
Cash and cash equivalents			$	734					$	291
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)			213						16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)			2,645						2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)			1,304						1,207
Regulatory balancing accounts			3,264						2,999
Other			1,624						1,784
Regulatory assets			296						496
Inventories
Gas stored underground and fuel oil			91						44
Materials and supplies			751						552
Wildfire Fund asset			460						461
Other			1,433						882
Total current assets			12,815						11,077
Property, Plant, and Equipment
Electric			74,772						69,482
Gas			28,226						25,979
Construction work in progress			4,137						3,479
Financing lease and other			19						20
Total property, plant, and equipment			107,154						98,960
Accumulated depreciation			(30,946)						(29,134)
Net property, plant, and equipment			76,208						69,826
Other Noncurrent Assets
Regulatory assets			16,443						9,207
Customer credit trust			745						—
Nuclear decommissioning trusts			3,297						3,798
Operating lease right of use asset			1,311						1,234
Wildfire Fund asset			4,847						5,313
Income taxes receivable			9						9
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)			2,969						2,863
Total other noncurrent assets			29,621						22,424
TOTAL ASSETS			$	118,644					$	103,327

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

			Balance at December 31,
			2022						2021
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings			$	2,055					$	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)			2,268						4,481
Accounts payable
Trade creditors			2,888						2,855
Regulatory balancing accounts			1,658						1,121
Other			778						679
Operating lease liabilities			231						468
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)			626						481
Wildfire-related claims			1,912						2,722
Other			3,372						2,436
Total current liabilities			15,788						17,427
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)			47,742						38,225
Regulatory liabilities			17,630						11,999
Pension and other postretirement benefits			231						860
Asset retirement obligations			5,912						5,298
Deferred income taxes			2,732						3,177
Operating lease liabilities			1,243						810
Other			4,291						4,308
Total noncurrent liabilities			79,781						64,677
Equity
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates			32,887						35,129
Treasury stock, at cost; 247,743,590 and 477,743,590 shares at respective dates			(2,517)						(4,854)
Reinvested earnings			(7,542)						(9,284)
Accumulated other comprehensive loss			(5)						(20)
Total shareholders’ equity			22,823						20,971
Noncontrolling Interest - Preferred Stock of Subsidiary			252						252
Total equity			23,075						21,223
TOTAL LIABILITIES AND EQUITY			$	118,644					$	103,327

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

			Year ended December 31,
			2022						2021						2020
Cash Flows from Operating Activities
Net income (loss)			$	1,814					$	(88)					$	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning			3,856						3,403						3,468
Bad Debt Expense			143						154						150
Allowance for equity funds used during construction			(184)						(133)						(140)
Deferred income taxes and tax credits, net			(452)						1,783						1,097
Reorganization items, net (Note 2)			—						(73)						1,458
Wildfire fund expense			477						517						413
Disallowed capital expenditures			15						—						17
Other			517						248						249
Effect of changes in operating assets and liabilities:
Accounts receivable			(757)						(589)						(1,182)
Wildfire-related insurance receivable			453						(723)						1,564
Inventories			(246)						(32)						6
Accounts payable			627						117						58
Wildfire-related claims			(810)						472						(16,525)
Other current assets and liabilities			17						244						(1,079)
Regulatory assets, liabilities, and balancing accounts, net			(1,131)						(2,266)						(2,451)
Liabilities subject to compromise			—						—						413
Contributions to Wildfire fund			(193)						(193)						(5,200)
Other noncurrent assets and liabilities			(425)						(579)						(142)
Net cash provided by (used in) operating activities			3,721						2,262						(19,130)
Cash Flows from Investing Activities
Capital expenditures			(9,584)						(7,689)						(7,690)
Proceeds from sale of the SFGO			—						749						—
Proceeds from sales and maturities of nuclear decommissioning trust investments			3,316						1,678						1,518
Purchases of nuclear decommissioning trust investments			(3,208)						(1,702)						(1,590)
Proceeds from sales and maturities of customer credit trust investments			250						—						—
Purchases of customer credit trust investments			(1,022)						—						—
Other			34						59						14
Net cash used in investing activities			(10,214)						(6,905)						(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility			—						—						500
Repayments of debtor-in-possession credit facility			—						—						(2,000)
Debtor-in-possession credit facility debt issuance costs			—						—						(6)
Bridge facility financing fees			—						—						(73)
Borrowings under credit facilities			10,130						9,730						8,554
Repayments under credit facilities			(9,750)						(9,976)						(3,949)
Credit facilities financing fees			—						(9)						(22)

Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates			—						300						1,448
Short-term debt matured			(300)						(1,450)						—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $178 at respective dates			4,271						4,624						13,497
Repayment of long-term debt			(5,968)						(87)						(764)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees of $36, $0 and $0 at respective dates			7,464						—						—
Repayment of SB 901 recovery bonds			(33)						—						—
Proceeds from issuance of AB 1054 recovery bonds, net of financing fees of $11, $10 and $0 at respective dates			972						850						—
Repayment of AB 1054 recovery bonds			(18)						—						—
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates			312						—						—
Proceeds from sale of future revenue from transmission tower license sales, net of fees			—						370						—
Exchanged debt financing fees			—						—						(103)
Common stock issued			—						—						7,582
Equity Units issued			—						—						1,304
Other			53						(29)						(40)
Net cash provided by financing activities			7,133						4,323						25,928
Net change in cash, cash equivalents, and restricted cash			640						(320)						(950)
Cash, cash equivalents, and restricted cash at January 1			307						627						1,577
Cash, cash equivalents, and restricted cash at December 31			$	947					$	307					$	627
Less: Restricted cash and restricted cash equivalents			(213)						(16)						(143)
Cash and cash equivalents at December 31			$	734					$	291					$	484

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized			$	(1,607)					$	(1,404)					$	(1,563)
Income taxes, net			—						99						—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable			$	1,174					$	1,311					$	515
Operating lease liabilities arising from obtaining ROU assets			529						100						13
Common stock issued in satisfaction of liabilities			—						—						8,276
Changes to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement			(2,337)						4,854						—

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, 2019			529,236,741						$	13,038					—						$	—					$	(7,892)					$	(10)					$	5,136					$	252					$	5,388
Net loss			—						—						—						—						(1,304)						—						(1,304)						—						(1,304)
Other comprehensive loss			—						—						—						—						—						(17)						(17)						—						(17)
Common stock issued, net			1,455,441,932						15,854						—						—						—						—						15,854						—						15,854
Equity units issued			—						1,304						—						—						—						—						1,304						—						1,304
Stock-based compensation amortization			—						28						—						—						—						—						28						—						28
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

(1) Excludes 477,743,590 shares of common stock issued to ShareCo. 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,
			2022						2021						2020
Operating Revenues
Electric			$	15,060					$	15,131					$	13,858
Natural gas			6,620						5,511						4,611
Total operating revenues			21,680						20,642						18,469
Operating Expenses
Cost of electricity			2,756						3,232						3,116
Cost of natural gas			2,100						1,149						782
Operating and maintenance			9,725						10,194						8,707
SB 901 securitization charges, net			608						—						—
Wildfire-related claims, net of recoveries			237						258						251
Wildfire Fund expense			477						517						413
Depreciation, amortization, and decommissioning			3,856						3,403						3,469
Total operating expenses			19,759						18,753						16,738
Operating Income			1,921						1,889						1,731
Interest income			162						22						39
Interest expense			(1,658)						(1,373)						(1,111)
Other income, net			595						512						470
Reorganization items, net			—						(12)						(310)
Income Before Income Taxes			1,020						1,038						819
Income tax provision (benefit)			(1,206)						900						408
Net Income			2,226						138						411
Preferred stock dividend requirement			14						14						14
Income Attributable to Common Stock			$	2,212					$	124					$	397

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

			Year ended December 31,
			2022						2021						2020
Net Income			$	2,226					$	138					$	411
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $2, $1, and $2, at respective dates)			6						(4)						(6)
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively)			(5)						—						—
Total other comprehensive income (loss)			1						(4)						(6)
Comprehensive Income			$	2,227					$	134					$	405

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)

			Balance At December 31,
			2022						2021
ASSETS
Current Assets
Cash and cash equivalents			$	609					$	165
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates)			213						16
Accounts receivable
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates)			2,645						2,345
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates)			1,304						1,207
Regulatory balancing accounts			3,264						2,999
Other			1,633						1,932
Regulatory assets			296						496
Inventories
Gas stored underground and fuel oil			91						44
Materials and supplies			751						552
Wildfire Fund asset			460						461
Other			1,421						869
Total current assets			12,687						11,086
Property, Plant, and Equipment
Electric			74,772						69,482
Gas			28,226						25,979
Construction work in progress			4,137						3,480
Financing lease			18						18
Total property, plant, and equipment			107,153						98,959
Accumulated depreciation			(30,946)						(29,131)
Net property, plant, and equipment			76,207						69,828
Other Noncurrent Assets
Regulatory assets			16,443						9,207
Customer credit trust			745						—
Nuclear decommissioning trusts			3,297						3,798
Operating lease right of use asset			1,311						1,232
Wildfire Fund asset			4,847						5,313
Income taxes receivable			7						7
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates)			2,834						2,706
Total other noncurrent assets			29,484						22,263
TOTAL ASSETS			$	118,378					$	103,177

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,
			2022						2021
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings			$	2,055					$	2,184
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates)			2,241						4,455
Accounts payable
Trade creditors			2,886						2,853
Regulatory balancing accounts			1,658						1,121
Other			747						648
Operating lease liabilities			231						467
Interest payable (includes $116 million and $3 million related to VIEs at respective dates)			573						430
Wildfire-related claims			1,912						2,722
Other			3,067						2,430
Total current liabilities			15,370						17,310
Noncurrent Liabilities
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates)			43,155						33,632
Regulatory liabilities			17,630						11,999
Pension and other postretirement benefits			160						764
Asset retirement obligations			5,912						5,298
Deferred income taxes			3,090						3,409
Operating lease liabilities			1,243						810
Other			4,334						4,345
Total noncurrent liabilities			75,524						60,257
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			29,280						28,286
Reinvested earnings			(3,368)						(4,247)
Accumulated other comprehensive loss			(8)						(9)
Total shareholders’ equity			27,484						25,610
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	118,378					$	103,177

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

			Year ended December 31,
			2022						2021						2020
Cash Flows from Operating Activities
Net income			$	2,226					$	138					$	411
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning			3,856						3,403						3,469
Bad Debt Expense			143						154						150
Allowance for equity funds used during construction			(184)						(133)						(140)
Deferred income taxes and tax credits, net			(319)						1,846						1,141
Reorganization items, net (Note 2)			—						(41)						(90)
Wildfire Fund expense			477						517						413
Disallowed capital expenditures			15						—						17
Other			102						172						220
Effect of changes in operating assets and liabilities:
Accounts receivable			(763)						(584)						(1,160)
Wildfire-related insurance receivable			453						(723)						1,564
Inventories			(246)						(32)						6
Accounts payable			627						44						(24)
Wildfire-related claims			(810)						472						(16,525)
Other current assets and liabilities			16						251						(1,141)
Regulatory assets, liabilities, and balancing accounts, net			(1,131)						(2,266)						(2,451)
Liabilities subject to compromise			—						—						401
Contributions to Wildfire Fund			(193)						(193)						(5,200)
Other noncurrent assets and liabilities			(438)						(577)						(108)
Net cash provided by (used in) operating activities			3,831						2,448						(19,047)
Cash Flows from Investing Activities
Capital expenditures			(9,584)						(7,689)						(7,690)
Proceeds from sale of the SFGO			—						749						—
Proceeds from sales and maturities of nuclear decommissioning trust investments			3,316						1,678						1,518
Purchases of nuclear decommissioning trust investments			(3,208)						(1,702)						(1,590)
Proceeds from sales and maturities of customer credit trust investments			250						—						—
Purchases of customer credit trust investments			(1,022)						—						—
Proceeds from (repayments of) intercompany note to PG&E Corporation			145						(145)						—
Other			34						59						14
Net cash used in investing activities			(10,069)						(7,050)						(7,748)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility			—						—						500
Repayments of debtor-in-possession credit facility			—						—						(2,000)
Debtor-in-possession credit facility debt issuance costs			—						—						(6)
Bridge facility financing fees			—						—						(33)
Borrowings under credit facilities			10,130						9,730						8,554
Repayments under credit facilities			(9,750)						(9,976)						(3,949)

Credit facilities financing fees			—						(9)						(22)
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates			—						300						1,448
Short-term debt matured			(300)						(1,450)						—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $88 at respective dates			4,271						4,624						8,837
Repayment of long-term debt			(5,941)						(59)						(100)
Proceeds from issuance of SB 901 recovery bonds, net of financing fees of $36, $0 and $0 at respective dates			7,464						—						—
Repayment of SB 901 recovery bonds			(33)						—						—
Proceeds from AB 1054 recovery bonds, net issuance costs of $11, $10, and $0 at respective dates			972						850						—
Repayment of AB 1054 recovery bonds			(18)						—						—
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates			312						—						—
Proceeds from sale of future revenue from transmission tower license sales, net of fees			—						370						—
Exchanged debt financing fees			—						—						(103)
Preferred stock dividends paid			(70)						—						—
Common stock dividends paid			(1,275)						—						—
Equity contribution from PG&E Corporation			994						—						12,986
Other			123						(1)						(42)
Net cash provided by financing activities			6,879						4,379						26,070
Net change in cash, cash equivalents, and restricted cash			641						(223)						(725)
Cash, cash equivalents, and restricted cash at January 1			181						404						1,129
Cash, cash equivalents, and restricted cash at December 31			$	822					$	181					$	404
Less: Restricted cash and restricted cash equivalents			(213)						(16)						(143)
Cash and cash equivalents at December 31			$	609					$	165					$	261

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized			$	(1,374)					$	(1,198)					$	(1,458)
Income taxes, net			—						99						—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable			$	1,174					$	1,311					$	515
Operating lease liabilities arising from obtaining ROU assets			529						100						13
Common stock equity infusion from PG&E Corporation used to satisfy liabilities			—						—						6,750

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, 2019			$	258					$	1,322					$	8,550					$	(4,796)					$	1					$	5,335
Net income			—						—						—						411						—						411
Other comprehensive loss			—						—						—						—						(6)						(6)
Equity contribution			—						—						19,736						—						—						19,736
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

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: BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including the Ad Hoc Committee of Holders of Trade Claims (the “Trade Committee”). The Trade Committee appealed the Confirmation Order’s holding, which awarded post-petition interest on general unsecured claims at the federal judgment rate of 2.59%. The Trade Committee is seeking for its members to receive post-petition interest at the rates specified under their contracts or the rate established under California state law, which is 10%. The Bankruptcy Court and the federal district court held that the Trade Committee’s members are entitled to post-petition interest at the federal judgment rate. On June 8, 2021, the Trade Committee appealed the federal district court decision to the Ninth Circuit Court of Appeals. On August 29, 2022, a three-judge panel of the Ninth Circuit Court of Appeals reversed the federal district court decision 2-1. On September 12, 2022, the Utility filed a petition for en banc review, which was denied on October 5, 2022. On February 2, 2023, the Utility filed a petition for a writ of certiorari to the Supreme Court of the United States. PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the post-petition interest matter, but the amount of that loss is not reasonably estimable at this time. If the Ninth Circuit Court of Appeals decision is not reversed, then the matter would be remanded to the Bankruptcy Court to evaluate the rate of interest for each individual contract, the conditions under which the contract rate applies, and whether payment of interest under state law would be warranted for each contract and claimant. These proceedings therefore will require extensive discovery and motion practice before the Bankruptcy Court with respect to each of these claims on a variety of contractual issues and equitable considerations. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings or any further appeals.

Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.

Unresolved Chapter 11 Claims

PG&E Corporation and the Utility have received over 100,000 proofs of claim since January 29, 2019, of which approximately 80,000 were channeled to a trust for the benefit of holders of certain subrogation claims (the “Subrogation Wildfire Trust”) and the Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims, including asserted litigation claims, trade creditor claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order. Amounts expected to be allowed are reflected as current liabilities in the Consolidated Balance Sheets.

Holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).

In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 15 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 15 under the heading “Securities Class Action Litigation.”

In addition to filing objections in the Bankruptcy Court to claims that were subject to certain defenses which allowed PG&E Corporation and the Utility to file objections expunging those claims on an omnibus basis, PG&E Corporation and the Utility are working to resolve disputed claims, including Subordinated Debt Claims and HoldCo Rescission or Damage Claims. By order of the Bankruptcy Court, the current deadline for PG&E Corporation and the Utility to object to claims is June 20, 2023.

NOTE 3: 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, 2022, the Utility also holds $213 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)			2022						2021
Electric
Revenue from contracts with customers
Residential			$	6,130					$	6,089
Commercial			5,416						5,042
Industrial			1,626						1,493
Agricultural			1,830						1,565
Public street and highway lighting			77						73
Other, net (1)			(247)						(84)
Total revenue from contracts with customers - electric			14,832						14,178
Regulatory balancing accounts (2)			228						953
Total electric operating revenue			$	15,060					$	15,131
Natural gas
Revenue from contracts with customers
Residential			$	3,353					$	2,759
Commercial			1,005						713
Transportation service only			1,534						1,346
Other, net (1)			163						140
Total revenue from contracts with customers - gas			6,055						4,958
Regulatory balancing accounts (2)			565						553
Total natural gas operating revenue			6,620						5,511
Total operating revenues			$	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, 2022, 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.

As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022.

PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 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, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 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 15 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, 2022, 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)						2022						2021
Electricity generating facilities (1)			5 to 75						$	11,781					$	11,217
Electricity distribution facilities			10 to 70						41,061						37,723
Electricity transmission facilities			15 to 75						16,413						15,516
Natural gas distribution facilities			20 to 60						15,366						14,100
Natural gas transmission and storage facilities			5 to 66						9,859						9,067
Financing lease									18						18
Construction work in progress									4,137						3,480
General plant and other			5 to 50						8,518						7,838
Total property, plant, and equipment									107,153						98,959
Accumulated depreciation									(30,946)						(29,131)
Net property, plant, and equipment (2)									$	76,207					$	69,828

(1) Balance includes nuclear fuel inventories. 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 16 below.

(2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below.

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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020. 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 $81 million and $184 million during 2022, $56 million and $133 million during 2021, and $35 million and $140 million during 2020.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations:

(in millions)			2022						2021
ARO liability at beginning of year			$	5,298					$	6,412
Liabilities incurred			134						—
Revision in estimated cash flows			325						(1,378)
Accretion			213						287
Liabilities settled			(58)						(23)
ARO liability at end of year			$	5,912					$	5,298

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 4 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 total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “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.

The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020.

The increase of $614 million in the 2022 ARO liability at December 31, 2022 as compared to December 31, 2021 is primarily due to the update of the ARO associated with the Diablo Canyon power plant as described above; the creation of a new liability for the permanently abandoned electric transmission lines in connection with the Kincade SED Settlement (as defined in Note 15); increases in the probability that the Utility will be responsible for decommissioning certain hydroelectric generation facilities; increases in the costs associated with retiring gas transmission pipelines; and increases in escalation factors. The increase is offset by increases in the credit-adjusted risk-free rate from 2021 to 2022.

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 one retired facility at Humboldt Bay. 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 year ended December 31, 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, the Governor of California signed AB 180, which 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. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred.

Senate Bill 846

On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances.

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 will pay 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, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on 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 pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. 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, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements.

U.S. DOE’s Civil Nuclear Credit Program

On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (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 actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. 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 related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense on the Consolidated Statements of Income as eligible costs are incurred.

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, respectively, 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 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 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 order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the 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 2022 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, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, 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.

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 SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the 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 2022 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, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below.

Non-Consolidated VIEs

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, 2022, 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, 2022, it did not consolidate any of them.

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 evaluate and, where appropriate, update all assumptions quarterly. 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. During the year ended December 31, 2022, PG&E Corporation and the Utility updated assumptions related to the mitigation effectiveness and historical fire loss dataset to align with the risk modeling within the 2022 WMP. These updates did not change the estimated period of coverage, which continues to be 15 years from the inception of the Wildfire Fund.

As of December 31, 2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $935 million in Other non-current liabilities, $460 million in Current assets - Wildfire Fund asset, and $4.8 billion in Non-current assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 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, 2022, PG&E Corporation and the Utility had recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Wildfire Fund under AB 1054” in Note 15 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 10, “Derivatives” in Note 11, “Fair Value Measurements” in Note 12, and “Contingencies and Commitments” in Notes 15 and 16 below.

Voluntary Separation Program

In the second quarter of 2022, PG&E Corporation and the Utility enacted a VSP, which provides separation benefits to approximately 470 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance. During the year ended December 31, 2022, PG&E Corporation and the Utility recorded $80 million in Operating and maintenance expense on the Consolidated Statements of Income related to one-time cash payments in connection with the VSP. In addition, during the year ended December 31, 2022, VSP-related credits to employee retirement health savings accounts totaled $22 million. This amount will be paid using the PG&E Corporation and Utility postretirement medical plan trusts’ assets and does not impact income.

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, 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:
Loss on investments (net of taxes of $0, $0 and $3, respectively)			—						—						(6)						(6)
Unrecognized net actuarial gain (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 (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 13 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, 2021 consisted of the following:

(in millions, net of income tax)			Pension Benefits						Other Benefits						Total
Beginning balance			$	(39)					$	17					$	(22)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively)			1,007						137						1,144
Regulatory account transfer (net of taxes of $390 and $53, respectively)			(1,003)						(136)						(1,139)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)			(4)						10						6
Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively)(1)			4						(24)						(20)
Regulatory account transfer (net of taxes of $1 and $5, respectively) (1)			2						14						16
Net current period other comprehensive income			6						1						7
Ending balance			$	(33)					$	18					$	(15)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 13 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.

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2022 and 2021.

For the years ended December 31, 2022 and 2021, the Utility made total cash payments, including fixed and variable, of $2.3 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included 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.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements and the Oakland lease. 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 16 below.

PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. Property arrangements primarily consist of an office lease agreement for the Lakeside Building. 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 term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.

The Lease requires 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. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). On February 6, 2023, the process of subdividing the real estate was completed. If the option is exercised pursuant to the terms of the existing agreement then the Purchase Price would be paid in or around July 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, 2022, approximately 488,000 rentable square feet of the leased premises has been made available for use by the Utility. The Utility has recorded approximately $535 million in Operating lease right of use assets, approximately $214 million of leasehold improvements, which includes approximately $137 million that was provided to the Utility as lease incentives, and approximately $672 million in noncurrent Operating lease liabilities in the Consolidated Financial Statements related to the Lease.

In January 2023, approximately 110,000 of additional rentable square feet was made available for use by the Utility.

At December 31, 2022 and 2021, the Utility’s operating leases had a weighted average remaining lease term of 19.6 years and 6.04 years and a weighted average discount rate of 6.5% and 6.1%, respectively.

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

			Year Ended December 31,
(in millions)			2022						2021
Operating lease fixed cost			$	500					$	578
Operating lease variable cost			1,829						1,782
Total operating lease costs			$	2,329					$	2,360

At December 31, 2022, the Utility’s future expected operating lease payments were as follows:

(in millions)			December 31, 2022
2023			$	307
2024			150
2025			146
2026			143
2027			142
Thereafter			2,196
Total lease payments			3,084
Less imputed interest			(1,610)
Total			$	1,474

Recently Adopted Accounting Standards

Debt

In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

Reference Rate Reform

On April 1, 2020, PG&E Corporation and the Utility adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and elected the optional amendments for contract modifications prospectively. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. PG&E Corporation and the Utility adopted this ASU in December 2022 and will apply the guidance through December 31, 2024. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU.

NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

			Balance at December 31,												Recovery Period
(in millions)			2022						2021
Pension benefits (1)			$	120					$	708					Indefinitely
Environmental compliance costs			1,193						1,089						32 years
Utility retained generation (2)			86						133						4 years
Price risk management			177						216						17 years
Catastrophic event memorandum account (3)			1,085						1,119						1 - 3 years
Wildfire expense memorandum account (4)			439						347						TBD years
Fire hazard prevention memorandum account (5)			79						75						1 - 3 years
Fire risk mitigation memorandum account (6)			65						44						1 - 3 years
Wildfire mitigation plan memorandum account (7)			756						424						1 - 3 years
Deferred income taxes (8)			2,730						1,849						51 years
Insurance premium costs (9)			99						207						2 - 4 years
Wildfire mitigation balancing account (10)			327						273						1 - 3 years
Vegetation management balancing account (11)			2,276						1,411						1 - 3 years
COVID-19 pandemic protection memorandum accounts (12)			26						49						TBD years
Microgrid memorandum account (13)			213						163						1 - 3 years
Financing costs (14)			211						175						Various
SB 901 securitization (15)			5,378						—						30 years
AROs in excess of recoveries (16)			120						—						Various
Other			1,063						925						Various
Total long-term regulatory assets			$	16,443					$	9,207

(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, 2022 and 2021, $44 million and $49 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 have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.

(6) Includes costs primarily associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval.

(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019, the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, and the 2022 WMP for the period of January 1, 2022 through December 31, 2022. 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 rate cases, respectively.

(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2022. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) Represents vegetation management costs above 120% of adopted revenue requirements, 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, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded uncollectibles in the amount of $30 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $19 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 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings. Recovery periods vary because the balance consists of financing costs associated with debts that have different amortization periods depending on their maturity date.

(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 6 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 12 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods.

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, 2022 and 2021, the Utility had current regulatory liabilities of $1.12 billion and $698 million, respectively. At December 31, 2022, current regulatory liabilities consisted primarily of unrealized gains associated with the change in fair value of price risk management instruments that meet the definition of a derivative. An increase in natural gas prices has affected both the Utility’s gas and electric price risk management instruments, resulting in a deferral of $604 million. For more information, see Note 11 below. Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

			Balance at December 31,
(in millions)			2022						2021
Cost of removal obligations (1)			$	7,773					$	7,306
Recoveries in excess of AROs (2)			—						388
Public purpose programs (3)			1,062						946
Employee benefit plans (4)			904						1,229
Transmission tower wireless licenses (5)			430						446
SFGO sale (6)			264						343
SB 901 securitization (7)			5,800						—
Other			1,397						1,341
Total long-term regulatory liabilities			$	17,630					$	11,999

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

(2) 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 held in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 12 below.

(3) 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.

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

(5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $430 million, $300 million will be refunded to FERC-jurisdictional customers, and $130 million will be refunded to CPUC-jurisdictional customers.

(6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022.

(7) 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, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement. See Note 6 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.

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

			Receivable Balance at December 31,
(in millions)			2022						2021
Electric distribution (1)			$	448					$	—
Gas distribution and transmission (2)			72						—
Energy procurement (3)			684						310
Public purpose programs (4)			358						321
Fire hazard prevention memorandum account (5)			—						50
Fire risk mitigation memorandum account (6)			—						14
Wildfire mitigation plan memorandum account (7)			—						67
Wildfire mitigation balancing account (8)			2						91
General rate case memorandum accounts (9)			3						468
Vegetation management balancing account (10)			137						127
Insurance premium costs (11)			602						605
Wildfire expense memorandum account (12)			—						440
Residential uncollectibles balancing accounts (13)			126						127
Catastrophic event memorandum account			144						—
Other			688						379
Total regulatory balancing accounts receivable			$	3,264					$	2,999

			Payable Balance at December 31,
(in millions)			2022						2021
Electric distribution (1)			$	—					$	121
Electric transmission (14)			228						24
Gas distribution and transmission (2)			66						83
Energy procurement (3)			428						211
Public purpose programs (4)			272						259
Nuclear decommissioning adjustment mechanism (15)			8						137
SFGO sale			152						21
Other			504						265
Total regulatory balancing accounts payable			$	1,658					$	1,121

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

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

(3) 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.

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

(5) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(6) The FRMMA tracks costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(7) The WMPMA tracks costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts.

(8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery.

(9) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC.

(10) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery.

(11) The insurance premium costs 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 rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2022, and 2021 there were $48 million and $82 million, respectively, in insurance premium costs recorded in Current regulatory assets.

(12) The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022.

(13) 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.

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

(15) The nuclear decommissioning adjustment mechanism tracks costs primarily related to the closure of the Diablo Canyon power plant.

NOTE 5: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2022:

(in millions)			Termination Date						Maximum Facility Limit						Loans Outstanding						Letters of Credit Outstanding						Facility Availability
Utility revolving credit facility			June 2027						$	4,400		(1)			$	(1,930)					$	(998)					$	1,472
Utility receivables securitization program (2)			September 2024						1,389			(3)			(1,184)						—						205			(3)
PG&E Corporation revolving credit facility			June 2025						500						—						—						500
Total credit facilities									$	6,289					$	(3,114)					$	(998)					$	2,177

(1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 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 $1.0 billion and $1.5 billion depending on the time period. 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 July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility.

On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility.

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid.

On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation).

Intercompany Note Payable

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility securitized $975 million of these expenditures in 2022 and plans to securitize remaining expenditures in subsequent periods. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The payment dates for the Series 2022-A Senior Secured Recovery Bonds are January 15 and July 15 of each year, commencing on July 15, 2023 and continuing until the final maturity date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the Series 2022-A Senior Secured Recovery Bonds, including (1) the Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022 (“the Sale Agreement”), (2) the Recovery Property Servicing Agreement, dated as of November 30, 2022 (the “Servicing Agreement”), and the Administration Agreement, dated as of November 30, 2022 (the “Administration Agreement”).

Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property (as defined in the Amended Articles) created pursuant to the Wildfire Financing Law and the Financing Order (as defined in the Amended Articles) to PG&E Recovery Funding LLC; the Utility carries out the functions pursuant to the Servicing Agreement to determine the Fixed Recovery Charges (as defined in the Amended Articles); and the Utility provides corporate management services to PG&E Recovery Funding LLC pursuant to the Administration Agreement. The Utility used the proceeds of the sale of the Recovery Property in accordance with the Wildfire Financing Law and the Financing Order.

For more information on PG&E Recovery Funding LLC, see “Variable Interest Entities” in Note 3 above.

Long-Term Debt Issuances and Redemptions

Utility

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes.

On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

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 proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

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

									Balance at
(in millions)			Contractual Interest Rates						December 31, 2022						December 31, 2021
PG&E Corporation
Term Loan - Stated Maturity: 2025			variable rate (1)						$	2,681					$	2,709
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)						(26)
Unamortized discount/premium and debt issuance costs, net									(66)						(90)
Total PG&E Corporation Long-Term Debt									4,587						4,593
Utility
First Mortgage Bonds - Stated Maturity:
2022			variable rate (2)						—						500
2022			1.75%						—						2,500
2023			1.70% - 4.25%						2,075						3,575
2024			3.25% - 3.75%						1,800						800
2025			3.45% - 4.95%						1,925						1,475
2026			2.95% - 3.15%						2,551						2,551
2027			2.10% - 5.45%						3,000						2,550
2028			3.00% - 4.65%						1,975						1,975
2029			4.20%						400						—
2030			4.55%						3,100						3,100
2031			2.50% - 3.25%						3,000						3,000
2032			4.40% - 5.90%						1,050						—
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						—
Less: current portion, net of unamortized discount and debt issuance costs									(2,072)						(2,996)
Unamortized discount, premium and debt issuance costs, net									(195)						(190)
Total Utility First Mortgage Bonds									32,135						31,816
Recovery Bonds (3)									9,292						860
Less: current portion									(168)						(18)
DWR Loan (4)									312						—
Credit Facilities
Receivables securitization program - Stated Maturity: 2024			variable rate (5)						1,184						974
2-Year Term Loan - Stated Maturity: 2024			variable rate (6)						400						—
18-month Term Loan - Stated Maturity: 2023			variable rate (7)						—						1,441
Less: current portion									—						(1,441)
Total Utility Long-Term Debt									43,155						33,632
Total PG&E Corporation Consolidated Long-Term Debt									$	47,742					$	38,225

(1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively.

(2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%.

(3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates.

(4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance.

(5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%.

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

(7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below:

(in millions, except interest rates)			2023						2024						2025						2026						2027						Thereafter						Total
PG&E Corporation
Average fixed interest rate			—		%				—		%				—		%				—		%				—		%				5.13		%				5.13		%
Fixed rate obligations			$	—					$	—					$	—					$	—					$	—					$	2,000					$	2,000
Variable interest rate as of December 31, 2022			7.13		%				7.13		%				7.13		%				—		%				—		%				—		%				7.13		%
Variable rate obligations			$	28					$	28					$	2,625					$	—					$	—					$	—					$	2,681
Utility (1)
Average fixed interest rate			2.91		%				3.40		%				3.82		%				3.10		%				3.22		%				4.12		%				3.84		%
Fixed rate obligations			$	2,075					$	1,800					$	1,925					$	2,551					$	3,000					$	23,051					$	34,402
Variable interest rate as of December 31, 2022			—		%				5.54		%				—		%				—		%				—		%				—		%				5.54		%
Variable rate obligations			$	—					$	1,584					$	—					$	—					$	—					$	—					$	1,584
Recovery Bonds (2)
AB 1054 obligations			$	38					$	46					$	48					$	50					$	51					$	1,592					$	1,825
SB 901 obligations			$	130					$	129					$	135					$	141					$	146					$	6,786					$	7,467
Total consolidated debt			$	2,271					$	3,587					$	4,733					$	2,742					$	3,197					$	33,429					$	49,959

(1) The balance excludes DWR loan, see Note 3 - Government Assistance.

(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6.

NOTE 6: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers. The proceeds of the securitization were used to repay certain debt that the Utility had initially issued for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. (“CHT Decision”). As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The decision adopts a transaction structure comprised of four elements: (1) an initial shareholder contribution to the customer credit trust of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable.

On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches:

Tranche						Amount						Interest Rate						Final Maturity Date
A-1						$	540,000,000					3.594		%				June 1, 2032
A-2						$	540,000,000					4.263		%				June 1, 2038
A-3						$	360,000,000					4.377		%				June 3, 2041
A-4						$	1,260,000,000					4.451		%				December 1, 2049
A-5						$	900,000,000					4.674		%				December 1, 2053

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The payment dates for the Series 2022-A Recovery Bonds are June 1 and December 1 of each year, commencing on December 1, 2022 and continuing until the final maturity date.

On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision.

On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches:

Tranche						Amount						Interest Rate						Final Maturity Date
B-1						$	613,080,000					4.022		%				June 1, 2033
B-2						$	600,000,000					4.722		%				June 1, 2039
B-3						$	500,040,000					5.081		%				June 3, 2043
B-4						$	1,149,960,000					5.212		%				December 1, 2049
B-5						$	1,036,920,000					5.099		%				June 1, 2054

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024. The payment dates for the Series 2022-B Recovery Bonds are June 1 and December 1 of each year, commencing on June 1, 2023 and continuing until the final maturity date.

Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full scheduled principal amount of the 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 12). 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, 2022.

Also pursuant to the CHT decision, 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, previously recognized within wildfire-related claims expense, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. 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 sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. 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, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability pursuant to the CHT decision discussed above, as well as 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 7 below) and amortization of the regulatory asset and liability in the Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion, as the aforementioned tax benefits are recognized and recorded within deferred income taxes.

The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities:

SB 901 securitization regulatory asset (in millions)
Regulatory asset balance at inception			$	5,500
Amortization			(122)
Balance at December 31, 2022			$	5,378

SB 901 securitization regulatory liability (in millions)
Regulatory liability balance at inception			$	(5,540)
Amortization			308
Additions			(568)
Balance at December 31, 2022			$	(5,800)

NOTE 7: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 1,987,784,948 shares of common stock outstanding at December 31, 2022, which excludes 247,743,590 shares of common stock owned by ShareCo, and 230,000,000 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2022.

Equity Offerings

During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 138 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the equity units purchase contracts and subject to certain adjustments as provided therein. The settlement date of the equity unit purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts.

At the Market Equity Distribution Program

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement.

The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement.

On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement.

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.

On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are 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. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of the outstanding shares. At various dates throughout 2022, 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, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

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 December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. On December 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on December 20, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

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. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure 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. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock.

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 53,350,101 shares were available for future awards at December 31, 2022.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2022:

(in millions)			2022						2021						2020
Stock Options			$	—					$	—					$	3
Restricted stock units			60						35						15
Performance shares			55						21						17
Total compensation expense (pre-tax)			$	115					$	56					$	35
Total compensation expense (after-tax)			$	83					$	40					$	25

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, 2022, 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 2022 or 2021.

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, 2022.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2022:

			Number of Stock Options						Weighted Average Grant- Date Fair Value						Weighted Average Remaining Contractual Term						Aggregate Intrinsic Value
Outstanding at January 1			2,195,834						$	7.42											$	—
Granted (1)			—						—												—
Exercised			—						—												—
Forfeited or expired			(43,702)						10.23												—
Outstanding at December 31			2,152,132						7.36						2.41						—
Vested or expected to vest at December 31			2,152,132						7.36						2.41						—
Exercisable at December 31			2,152,132						$	7.36					2.41						$	—

(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 2022, 2021, and 2020 was $11.40, $11.01, and $9.25, respectively. The total fair value of restricted stock units that vested during 2022, 2021, and 2020 was $46 million, $19 million, and $31 million, respectively. The tax detriment from restricted stock units that vested in 2022 was $4 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, 2022, $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 1.48 years.

The following table summarizes restricted stock unit activity for 2022:

			Number of Restricted Stock Units						Weighted Average Grant- Date Fair Value
Nonvested at January 1			10,090,375						$	11.00
Granted			5,850,945						11.40
Vested			(4,175,008)						10.96
Forfeited			(788,192)						11.18
Nonvested at December 31			10,978,120						$	11.21

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 internal metric based awards. The weighted average grant-date fair value for performance shares granted during 2022, 2021, and 2020 was $13.44, $11.83, and $9.62 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, 2022, $43 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 0.94 years.

The following table summarizes activity for performance shares in 2022:

			Number of Performance Shares						Weighted Average Grant- Date Fair Value
Nonvested at January 1			8,567,009						$	9.64
Granted			3,105,604						13.44
Vested			—						—
Forfeited			(650,559)						10.15
Nonvested at December 31			11,022,054						$	10.68

NOTE 8: 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, 2022 and 2021, 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.

On December 31, 2022, 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, 2022, annual dividends on 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. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022. In addition to the dividends paid in arrears, the Utility paid approximately $11 million of dividends on redeemable preferred stock during the year ended December 31, 2022. On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023.

The Utility paid no dividends on preferred stock in 2021 or 2020.

NOTE 9: 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 2022, 2021, and 2020.

			Year Ended December 31,
(in millions, except per share amounts)			2022						2021						2020
Income (loss) available for common shareholders			$	1,800					$	(102)					$	(1,318)
Weighted average common shares outstanding, basic			1,987						1,985						1,257
Add incremental shares from assumed conversions:
Employee share-based compensation			8						—						—
Equity Units			137						—						—
Weighted average common shares outstanding, diluted			2,132						1,985						1,257
Total earnings (loss) per common share, diluted			$	0.84					$	(0.05)					$	(1.05)

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.

NOTE 10: 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)			2022						2021						2020						2022						2021						2020
Current:
Federal			$	(1)					$	—					$	(26)					$	(1)					$	—					$	(26)
State			—						1						(34)						—						—						(34)
Deferred:
Federal			(943)						543						258						(852)						588						290
State			(389)						296						171						(348)						316						185
Tax credits			(5)						(4)						(7)						(5)						(4)						(7)
Income tax provision (benefit)			$	(1,338)					$	836					$	362					$	(1,206)					$	900					$	408

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

			PG&E Corporation												Utility
			Year Ended December 31,
(in millions)			2022						2021						2022						2021
Deferred income tax assets:
Tax carryforwards			$	7,156					$	5,628					$	6,868					$	5,425
Compensation			157						185						80						108
Greenhouse gas allowance			239						157						239						157
Wildfire-related claims (1)			1,489						1,723						1,489						1,723
Operating lease liability			368						346						368						346
Transmission tower wireless licenses			254						266						254						266
Other (2)			197						121						177						136
Total deferred income tax assets			$	9,860					$	8,426					$	9,475					$	8,161
Deferred income tax liabilities:
Property related basis differences			9,374						8,847						9,363						8,835
Regulatory balancing accounts			1,376						1,193						1,376						1,193
Debt financing costs			465						501						465						501
Operating lease right of use asset			368						346						368						346
Income tax regulatory asset (3)			764						517						764						517
Other (4)			245						199						230						178
Total deferred income tax liabilities			$	12,592					$	11,603					$	12,566					$	11,570
Total net deferred income tax liabilities			$	2,732					$	3,177					$	3,091					$	3,409

(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 Tax Act.

(4) Amount primarily includes an environmental reserve.

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,
			2022						2021						2020						2022						2021						2020
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)			(75.8)						31.3						(15.3)						(26.9)						24.1						19.1
Effect of regulatory treatment of fixed asset differences (2)			(123.8)						(71.5)						39.0						(49.2)						(51.6)						(44.9)
Tax credits			(3.2)						(1.7)						1.5						(1.3)						(1.2)						(1.7)
Fire Victim Trust (3)			(160.9)						127.3						(44.9)						(64.0)						91.9						51.7
Bankruptcy and emergence			—						—						(37.6)						—						—						2.4
Other, net (4)			12.9						5.3						(2.1)						2.2						2.6						2.2
Effective tax rate			(329.8)		%				111.7		%				(38.4)		%				(118.2)		%				86.8		%				49.8		%

(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 2022, 2021, and 2020, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) The Utility includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2022, a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for difference between the liability recorded related to the Restructuring Support Agreement dated December 6, 2019 with the Official Committee of Tort Claimants and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020. PG&E Corporation includes the same adjustment as the Utility in these years as well as a permanent non-deductible equity backstop premium expense in 2020.

(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)			2022						2021						2020						2022						2021						2020
Balance at beginning of year			$	498					$	437					$	420					$	498					$	437					$	420
Reductions for tax position taken during a prior year			(1)						(23)						(43)						(1)						(23)						(43)
Additions for tax position taken during the current year			73						85						60						73						85						60
Settlements			—						(1)						—						—						(1)						—
Balance at end of year			$	570					$	498					$	437					$	570					$	498					$	437

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2022 for PG&E Corporation and the Utility was $31 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, 2022, 2021, and 2020, these amounts were immaterial.

Tax Settlements

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 deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. The Internal Revenue Service 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, 2022						Expiration Year
Federal:
Net operating loss carryforward - Pre-2018			$	3,447					2031 - 2036
Net operating loss carryforward - Post-2017			23,170						N/A
Tax credit carryforward			152						2029 - 2041
State:
Net operating loss carryforward			$	25,169					2039 - 2041
Tax credit carryforward			126						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

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. Half of the payment was paid in 2021, and the other half of the payment was paid in 2022.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). Due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. 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.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. From inception through December 31, 2022, the Fire Victim Trust exchanged Plan Shares in the aggregate amount of 230,000,000 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, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. On January 9, 2023, the Fire Victim Trust exchanged 60,000,000 Plan Shares and thereafter the Fire Victim Trust reported that it sold the applicable New Shares. An aggregate tax benefit of $256 million will be recorded in January 2023. For more information, see Note 7 above.

NOTE 11: 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, 2022						December 31, 2021
Natural Gas (1) (MMBtus (2))						Forwards, Futures and Swaps						171,212,813						173,361,635
						Options						27,785,000						14,420,000
Electricity (MWh)						Forwards, Futures and Swaps						10,814,728						10,283,639
						Options						215,600						288,000
						Congestion Revenue Rights (3)						205,743,505						239,857,610

(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, 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

As of December 31, 2021, 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			$	58					$	(9)					$	152					$	201
Other noncurrent assets – other			169						—						—						169
Current liabilities – other			(53)						9						18						(26)
Noncurrent liabilities – other			(216)						—						—						(216)
Total commodity risk			$	(42)					$	—					$	170					$	128

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 derivatives 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, 2022, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 12: 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, 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 11)
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 11)
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.

			Fair Value Measurements
			December 31, 2021
(in millions)			Level 1						Level 2						Level 3						Netting (1)						Total
Assets:
Short-term investments			$	289					$	—					$	—					$	—					$	289
Nuclear decommissioning trusts
Short-term investments			22						—						—						—						22
Global equity securities			2,504						—						—						—						2,504
Fixed-income securities			1,158						866						—						—						2,024
Assets measured at NAV			—						—						—						—						31
Total nuclear decommissioning trusts (2)			3,684						866						—						—						4,581
Price risk management instruments (Note 10)
Electricity			—						9						214						6						229
Gas			—						4						—						137						141
Total price risk management instruments			—						13						214						143						370
Rabbi trusts
Fixed-income securities			—						104						—						—						104
Life insurance contracts			—						76						—						—						76
Total rabbi trusts			—						180						—						—						180
Long-term disability trust
Short-term investments			6						—						—						—						6
Assets measured at NAV			—						—						—						—						132
Total long-term disability trust			6						—						—						—						138
TOTAL ASSETS			$	3,979					$	1,059					$	214					$	143					$	5,558
Liabilities:
Price risk management instruments (Note 10)
Electricity			$	—					$	11					$	248					$	(24)					$	235
Gas			—						10						—						(3)						7
TOTAL LIABILITIES			$	—					$	21					$	248					$	(27)					$	242

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

(2) Represents amount before deducting $783 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, 2022 and 2021.

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 11 above.

						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.

						Fair Value at
(in millions)						At December 31, 2021												Valuation Technique						Unobservable Input
Fair Value Measurement						Assets						Liabilities												Range (1)****/Weighted-Average Price (2)
Congestion revenue rights						$	188					$	93					Market approach						CRR auction prices						$ (40.77) - 2,265.94 / 0.40
Power purchase agreements						$	26					$	155					Discounted cash flow						Forward prices						$ (7.97) - 256.20 / 47.17

(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, 2022 and 2021, respectively:

			Price Risk Management Instruments
(in millions)			2022						2021
Liability balance as of January 1			$	(34)					$	(72)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)			233						38
Asset (Liability) balance as of December 31			$	199					$	(34)

(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, 2022 and December 31, 2021, 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, 2022												At December 31, 2021
(in millions)			Carrying Amount						Level 2 Fair Value						Carrying Amount						Level 2 Fair Value
Debt (Note 5)
PG&E Corporation			$	4,355					$	4,490					$	4,619					$	4,796
Utility			32,847						27,666						31,816						35,803

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, 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
As of December 31, 2021
Nuclear decommissioning trusts
Short-term investments			$	22					$	—					$	—					$	22
Global equity securities			479						2,066						(10)						2,535
Fixed-income securities			1,938						98						(12)						2,024
Total (1)			$	2,439					$	2,164					$	(22)					$	4,581

(1) Represents amounts before deducting $575 million and $783 million as of December 31, 2022 and December 31, 2021, 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, 2022
Less than 1 year			$	42
1–5 years			624
5–10 years			400
More than 10 years			819
Total maturities of fixed-income securities			$	1,885

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

(in millions)			2022						2021						2020
Proceeds from sales and maturities of nuclear decommissioning trust investments			$	3,316					$	1,678					$	1,518
Gross realized gains on securities			2						286						159
Gross realized losses on securities			(3)						(19)						(41)

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, 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, 2022
Less than 1 year			$	79
1–5 years			123
5–10 years			120
More than 10 years			186
Total maturities of fixed-income securities			$	508

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

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

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

NOTE 13: 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 2022 and 2021:

Pension Plan

(in millions)			2022						2021
Change in plan assets:
Fair value of plan assets at beginning of year			$	21,895					$	20,759
Actual return on plan assets			(4,916)						1,693
Company contributions			339						335
Benefits and expenses paid			(949)						(892)
Fair value of plan assets at end of year			$	16,369					$	21,895
Change in benefit obligation:
Benefit obligation at beginning of year			$	22,759					$	23,172
Service cost for benefits earned			575						587
Interest cost			692						645
Actuarial gain (1)			(6,471)						(752)
Plan amendments			—						—
Benefits and expenses paid			(947)						(893)
Benefit obligation at end of year (2)			$	16,608					$	22,759
Funded Status:
Current liability			$	(8)					$	(9)
Noncurrent liability			(231)						(856)
Net liability at end of year			$	(239)					$	(865)

(1) The actuarial gain for the year ended December 31, 2022 and December 31, 2021 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 $15.4 billion and $20.4 billion at December 31, 2022 and 2021, respectively.

Postretirement Benefits Other than Pensions

(in millions)			2022						2021
Change in plan assets:
Fair value of plan assets at beginning of year			$	3,102					$	2,995
Actual return on plan assets			(693)						193
Company contributions			26						10
Plan participant contribution			81						80
Benefits and expenses paid			(180)						(176)
Fair value of plan assets at end of year			$	2,336					$	3,102
Change in benefit obligation:
Benefit obligation at beginning of year			$	1,766					$	1,876
Service cost for benefits earned			62						63
Interest cost			53						51
Actuarial gain (1)			(486)						(152)
Benefits and expenses paid			(162)						(156)
Federal subsidy on benefits paid			3						4
Plan participant contributions			81						80
VSP related termination benefits (3)			22						—
Benefit obligation at end of year			$	1,339					$	1,766
Funded Status: (2)
Noncurrent asset			$	997					$	1,340
Noncurrent liability			—						(4)
Net asset at end of year			$	997					$	1,336

(1) 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. The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes

(2) At December 31, 2022 and 2021, 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 $259 million and $266 million as of December 31, 2022, and $363 million and $359 million as of December 31, 2021, respectively.

(3) Represents VSP-related credits to employee retirement health savings accounts. See Note 3 above.

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)			2022						2021						2020
Service cost for benefits earned (1)			$	575					$	587					$	530
Interest cost			692						645						713
Expected return on plan assets			(1,189)						(1,046)						(1,044)
Amortization of prior service cost			(4)						(6)						(6)
Amortization of net actuarial loss			2						6						3
Net periodic benefit cost			76						186						196
Less: transfer to regulatory account (2)			254						147						136
Total expense recognized			$	330					$	333					$	332

(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)			2022						2021						2020
Service cost for benefits earned (1)			$	62					$	63					$	61
Interest cost			53						51						63
Expected return on plan assets			(130)						(137)						(138)
Amortization of prior service cost			7						14						14
Amortization of net actuarial loss			(40)						(33)						(21)
Special termination benefits			22						—						—
Net periodic benefit cost			$	(26)					$	(42)					$	(21)

(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,
			2022						2021						2020						2022						2021						2020
Discount rate			5.54		%				3.03		%				2.77		%				5.50 - 5.54%						2.97 - 3.04%						2.67 - 2.80%
Rate of future compensation increases			3.80		%				3.80		%				3.80		%				N/A						N/A						N/A
Expected return on plan assets			6.10		%				5.50		%				5.10		%				3.70 - 7.30%						3.30 - 6.40%						3.10 - 6.10%
Interest crediting rate for cash balance plan			4.19		%				1.95		%				1.95		%				N/A						N/A						N/A

The assumed health care cost trend rate as of December 31, 2022 was 6.5%, 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 6.1% compares to a ten-year actual return of 5.8%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 848 Aa-grade non-callable bonds at December 31, 2022. 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
			2023						2022						2021						2023						2022						2021
Global equity securities			26		%				30		%				30		%				28		%				26		%				36		%
Absolute return			1		%				2		%				2		%				1		%				1		%				1		%
Real assets			8		%				8		%				8		%				3		%				3		%				5		%
Fixed-income securities			65		%				60		%				60		%				68		%				70		%				58		%
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, 2022 and 2021.

			Fair Value Measurements
			At December 31,
			2022																								2021
(in millions)			Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Pension Plan:
Short-term investments			$	461					$	126					$	—					$	587					$	552					$	255					$	—					$	807
Global equity securities			1,430						—						—						1,430						2,074						424						—						2,498
Absolute Return			—						—						—						—						—						1						—						1
Real assets			426						—						—						426						632						—						—						632
Fixed-income securities			1,946						6,086						8						8,040						2,729						7,388						27						10,144
Assets measured at NAV			—						—						—						5,886						—						—						—						7,972
Total			$	4,263					$	6,212					$	8					$	16,369					$	5,987					$	8,068					$	27					$	22,054
PBOP Plans:
Short-term investments			$	26					$	—					$	—					$	26					$	31					$	—					$	—					$	31
Global equity securities			83						—						—						83						105						—						—						105
Real assets			29						—						—						29						34						—						—						34
Fixed-income securities			406						702						1						1,109						776						875						1						1,652
Assets measured at NAV			—						—						—						1,100						—						—						—						1,296
Total			$	544					$	702					$	1					$	2,347					$	946					$	875					$	1					$	3,118
Total plan assets at fair value																					$	18,716																							$	25,172

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $11 million and $175 million at December 31, 2022 and 2021, 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, 2022 or 2021.

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, 2022 and 2021:

(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
(in millions)
For the year ended December 31, 2021			Fixed-Income
Balance at beginning of year			$	12
Actual return on plan assets:
Relating to assets still held at the reporting date			6
Relating to assets sold during the period			(7)
Purchases, issuances, sales, and settlements:
Purchases			22
Settlements			(6)
Balance at end of year			$	27

There were no material transfers out of Level 3 in 2022 or 2021.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $339 million to the pension benefit plans and $26 million to the other benefit plans in 2022. 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. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2022. 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 2023. PG&E Corporation and the Utility did not request to make contributions to the other postretirement benefit plans in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2022, 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
2023			907						97						(4)
2024			996						98						(4)
2025			1028						100						(4)
2026			1057						94						(4)
2027			1,082						94						(4)
Thereafter in the succeeding five years			5,702						475						(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 $144 million, $133 million, and $119 million in 2022, 2021, and 2020, 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 14: 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)			2022						2021						2020
Utility revenues from:
Administrative services provided to PG&E Corporation			$	3					$	3					$	3
Utility expenses from:
Administrative services received from PG&E Corporation			$	104					$	82					$	108
Utility employee benefit due to PG&E Corporation			85						39						34

At December 31, 2022 and 2021, the Utility had receivables of $33 million and $173 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 $46 million and $19 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

NOTE 15: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when 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.

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 such 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 transmission 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.

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 and the upper end of the range because, as described above, 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 and the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire. 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.

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.

On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed a complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation. As of December 31, 2022, $5.45 million has been paid pursuant to the Kincade Stipulation.

On July 14, 2022, the CPUC issued final approval of a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, for which it may not seek recovery. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In the third quarter of 2021, PG&E Corporation and the Utility recorded $40 million within Other current liabilities in connection with the Kincade SED Settlement. As of December 31, 2022, $20 million has been paid to California’s General Fund pursuant to the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 113 complaints on behalf of at least 2,720 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. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022.

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 April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The court scheduled a hearing on this summary adjudication motion for August 5, 2022, which it vacated on July 29, 2022. On October 26, 2022, PG&E Corporation and the Utility entered an agreement with substantially all of the insurance subrogation plaintiffs to resolve their claims arising from the 2019 Kincade fire.

Additionally, 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 $800 million as of December 31, 2021 (before available insurance). 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 additional charges during 2022 for potential losses in connection with the 2019 Kincade fire of $225 million, for an aggregate liability of $1.025 billion (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) 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, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021			$	769
Accrued Losses			225
Payments			(344)
Balance at December 31, 2022			$	650

The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2022, the Utility recorded an insurance receivable for the full amount of $430 million.

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.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts. On May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 3, 2023, the Shasta County District Attorney’s Office filed a superseding charging document, which charges the Utility with the 11 remaining counts. The court has set a trial date on those charges for June 6, 2023.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. If convicted of any of the charges, the Utility currently believes that its total losses associated with the fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement 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. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred.

Various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 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. The court has set a trial date in the coordinated proceeding for August 14, 2023.

In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. 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. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). 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 additional charges for potential losses in connection with the 2020 Zogg fire of $25 million, for an aggregate liability of $400 million (before available insurance).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than state fire suppression costs, (iv) evacuation costs, or (v) 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 2020 Zogg fire since December 31, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021			$	211
Accrued Losses			25
Payments			(204)
Balance at December 31, 2022			$	32

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, 2022, the Utility recorded an insurance receivable for $370 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 $30 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, 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”). 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.

The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing.

On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the court entered the judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation and the Utility recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation. As of December 31, 2022, $30.75 million has been paid pursuant to the Dixie Stipulation.

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

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 81 complaints on behalf of at least 2,094 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 2, 2023, the court vacated the prior trial date and continued it to August 28, 2023. PG&E Corporation and the Utility expect to enter 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 $1.15 billion as of the year ended December 31, 2021 (before available recoveries). As a result of the public entities settlement, the aggregate liability increased to $1.175 billion as of December 31, 2022.

PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion represent only claims based on the doctrine of inverse condemnation and 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) evacuation 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 park 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, 2021.

Loss Accrual (in millions)
Balance at December 31, 2021			$	1,150
Accrued Losses			25
Payments			(44)
Balance at December 31, 2022			$	1,131

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, 2022, the Utility recorded an insurance receivable of $530 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 $370 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2022, the Utility recorded a Wildfire Fund receivable of $175 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. The Utility also recorded a $115 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 $388 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. The WEMA regulatory asset increased by $41 million during the year ended December 31, 2022.

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, 13 structures damaged, and 78 structures destroyed 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 DOJ, and PG&E Corporation and the Utility are cooperating with the investigation. PG&E Corporation and the Utility have received document and information requests from the DOJ. 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 and other entities may also be investigating the 2022 Mosquito fire. It is uncertain when any such investigations will be complete.

As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately six complaints on behalf of at least 236 individual plaintiffs related to the 2022 Mosquito fire and expect that they may receive further such complaints. PG&E Corporation and the Utility also are aware of a complaint on behalf of the Placer County Water Agency and 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.

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

PG&E Corporation’s and the Utility’s accrued estimated losses represent only claims based on the doctrine of inverse condemnation and 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) evacuation costs, or (v) any other amounts that are not reasonably estimable. The Utility’s accrued estimated losses also do not include any assumptions regarding offsetting recoveries from third-parties (outside of the Utility’s insurers).

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 Utility has liability insurance coverage for third-party liability in an aggregate amount of $940 million, with a deductible of $60 million. As of December 31, 2022, the Utility recorded an insurance receivable of $45 million for probable insurance recoveries in connection with the 2022 Mosquito fire. As of December 31, 2022, the Utility also recorded a $10 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 $50 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, 2022 are:

Potential Recovery Source (in millions)			2022 Mosquito fire						2021 Dixie fire
Insurance			$	45					$	530
FERC TO rates			10						115
WEMA			50						388
Wildfire Fund			—						175
Probable recoveries at December 31, 2022			$	105					$	1,208

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 April 2022, the Utility purchased approximately $725 million in non-wildfire liability coverage for the period from April 1, 2022 to April 1, 2023 at a cost of approximately $154 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million.

As of December 31, 2022, PG&E Corporation and the Utility had prepaid insurance of $424 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.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in excess liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2022, PG&E Corporation and the Utility recorded $430 million, $370 million, $530 million, and $45 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, 2021			$	—					$	563					$	270					$	414					$	1,247
Accrued insurance recoveries (1)			45						(33)						33						—						45
Reimbursements			—						—						(185)						(313)						(498)
Balance at December 31, 2022			$	45					$	530					$	118					$	101					$	794

(1) For the year ended December 31, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $33 million.

During the year ended December 31, 2022, PG&E Corporation and the Utility resolved property related claims in the amount of $418 million, net of self-insured retention, of which approximately $13 million is reflected in Accounts receivable, other on the Consolidated Financial Statements (excluded from the table above).

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 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, 2022, the Utility recorded reductions of $115 million and $10 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, 2022, 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 $388 million and $50 million, respectively, as regulatory assets in the WEMA. Cost recovery for incremental insurance premiums is addressed through balancing account mechanisms.

Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which 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, 2022 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 $3.0 billion based on its 2022 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 December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 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 California’s three large 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.

As of December 31, 2022, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Related Insurance Recoveries Overview

As further described under the headings “Wildfire-Related Securities Class Action” 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. These securities claims are collectively referred to in this section as the “Wildfire-Related Securities Claims.”

Based on discussions with certain holders of Wildfire-Related Securities Claims, as well as the terms of the FVT D&O Claims Settlement Agreement (as defined below) and the settlement agreements with certain carriers of the D&O Insurance policies, PG&E Corporation believes it is probable that it will incur a loss in connection with the Wildfire-Related Securities Claims. As of December 31, 2022 and each as further described below:

• For the Wildfire-Related Securities Claims, based on discussions with the plaintiffs in the consolidated securities action, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for such claims, though actual losses could be greater or less than this estimate.

• For the Insurance Coverage Claims, PG&E Corporation entered into agreements with certain of its D&O Insurance carriers to settle the majority of the Insurance Coverage Claims and has received the full settlement amount of $272 million.

• For the Fire Victim Trust D&O Claims, the parties entered into a settlement agreement (the “FVT D&O Claims Settlement Agreement”) pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O insurance policy proceeds. PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

As a result, PG&E Corporation believes it is probable that it will incur a net loss of $145 million in connection with these matters. As of December 31, 2022, the net loss is reflected in Other income (expense), net on PG&E Corporation’s Consolidated Statements of Income.

In the event that one or more of the settlements in these matters does not become effective, some or all parties are expected to continue to litigate, and at least some of the amounts of PG&E Corporation’s expected liabilities will remain uncertain.

Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain then-current and former members of the boards of directors and certain then-current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility were named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and denominated In Re California North Bay Fire Derivative Litigation (now re-captioned Trotter v. Williams et al.). On April 13, 2018, the plaintiffs filed a consolidated complaint. On January 28, 2019, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s rights with respect to PG&E Corporation’s and the Utility’s claims, if any, directly or indirectly related to any of the Fires (as defined in the Plan) against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the Plan (the “Fire Victim Trust D&O Claims”). Any such recovery was limited to the extent of any D&O Insurance policy proceeds paid by any insurance carrier on behalf of PG&E Corporation or the Utility for amounts owed pursuant to their indemnification obligations in connection with such causes of action. On March 8, 2021, the court granted a stipulation by the parties to substitute the trustee for the Fire Victim Trust as the plaintiff.

On December 24, 2018, a separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On November 5, 2020, the court entered a stipulation and order to substitute the trustee for the Fire Victim Trust as the plaintiff.

On February 24, 2021, the trustee filed an amended complaint in the Trotter v. Chew action, asserting two direct claims for breach of fiduciary duty against certain of PG&E Corporation’s and the Utility’s former directors and officers. Neither PG&E Corporation nor the Utility was a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint, which the court sustained in part and overruled in part on November 8, 2021. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint, which the court overruled. On March 10, 2022, the defendants filed motions for summary judgment.

On July 26, 2022, PG&E Corporation, the Utility, certain former director and officer defendants, and the Fire Victim Trust entered into the FVT D&O Claims Settlement Agreement, pursuant to which PG&E Corporation, the Utility, and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O Insurance policy proceeds, and in return, the Fire Victim Trust released, among other things, any claims related to the assigned claims and the pursuit of the Trotter v. Chew action. Pursuant to the Plan, the settlement was paid solely from the insurance proceeds from the “Side B” D&O Insurance coverage. As a result of the FVT D&O Claims Settlement Agreement, the Trotter v. Chew action was dismissed with prejudice on December 29, 2022.

On January 25, 2019, a separate purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The plaintiff filed a request to dismiss this action, and on October 12, 2022, the court dismissed the action.

Securities Class Action Litigation

Wildfire-Related Securities Class Action

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’s opening brief for the appeal is due March 6, 2023, and the answering brief is due April 5, 2023.

Based on discussions with the plaintiffs in this matter, PG&E Corporation believes it is probable that it will incur a loss in connection with this matter. In the second quarter of 2022, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), 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 but is unable to reasonably estimate any additional loss because the amount of the liability has not been agreed or otherwise determined, and even if PG&E Corporation were to enter into an agreement with representatives of the plaintiffs in this matter (which would also resolve proofs of claim by these plaintiffs in the bankruptcy), any such agreement 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 agreement.

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

PG&E Corporation and the Utility intend to resolve claims filed in the bankruptcy relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, pursuant to the Plan. As described above, these claims consist of pre-petition claims 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 Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the 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 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, as well as insurance coverage that may be available with respect to the Subordinated Claims, these defenses may not prevail and any such insurance coverage 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. 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. There can be no assurance that such claims will not 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 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 and on December 15, 2021, PERA filed its opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in the Chapter 11 Cases and both PG&E Corporation and the Utility filed their answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. On January 13, 2023, PG&E Corporation and the Utility filed a joint motion with PERA requesting the Ninth Circuit Court of Appeals stay and hold PERA’s appeal in abeyance to allow the parties to continue to negotiate a settlement of the matters underlying the appeal. On January 25, 2023, the Ninth Circuit Court of Appeals entered an order granting the joint motion. PERA’s appeal to the Ninth Circuit Court of Appeals remains pending.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which would allow 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. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with the 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 file additional omnibus objections with respect to certain of the Subordinated Claims and to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.

Indemnification Obligations and D&O Insurance Coverage

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 and in the litigation matters enumerated above under the heading “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain D&O Insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and “Wildfire-Related Derivative Litigation,” and are in arbitration with certain carriers regarding, among other things, the applicability of one year of D&O Insurance policies to those matters (the “Insurance Coverage Claims”).

In July 2022, PG&E Corporation, the Utility, and the former director and officer defendants settled the majority of the Insurance Coverage Claims with certain of their D&O Insurance carriers. As a result of these agreements, PG&E Corporation received insurance proceeds in an aggregate amount of $272 million. Proceeds from the D&O Insurance coverage were paid to the Fire Victim Trust for the Fire Victim Trust D&O Claims, and PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

PG&E Corporation and the Utility additionally have potential 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 May 19, 2023.

NOTE 16: 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 assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves 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 in the TO rate case. 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 subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and the TO rate case for 2019 (“TO20”), respectively.

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (i) impact of the Tax Act on TO18 rates in January and February 2018 and (ii) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the fourth quarter of 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $258 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with 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 issuance of a final unappealable decision in the TO18 proceeding.

On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The TO20 rate case provides that the transmission revenue requirement and rates are to be updated annually on January 1, subject to true-up. The Utility is required to make a successor rate filing in 2023, which would go into effect on January 1, 2024.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

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%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. The Utility expects to issue the refund after the FERC issues a decision on the compliance filing.

2022 Cost of Capital Application

The Utility’s annual cost of capital adjustment mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the “Index”)) and (ii) 4.5% exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general, and the Utility in particular, to the same extent as the overall financial markets (the “2022 cost of capital application”). The 2022 cost of capital application requested that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure, ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure.

In September 2021, the cost of capital adjustment mechanism was triggered because the Index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.

On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes beginning on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application. As of December 31, 2022, the Utility had not recorded a reserve for refunds related to these memorandum accounts.

On November 3, 2022, the CPUC issued a final decision finding that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be implemented for 2022. The final decision retains the cost of capital previously authorized in the 2020 cost of capital proceeding, as adjusted, and closes this proceeding. On December 5, 2022, intervenors filed an application for rehearing. On December 20, 2022, the Utility filed a response to the application for rehearing.

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 $69 million and $77 million as of December 31, 2022 and December 31, 2021, respectively. These amounts were included in Other current liabilities on the Consolidated Financial Statements. 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 United States Bankruptcy Court for the Northern District of California 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. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

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 June 1, 2022, the California Supreme Court accepted certification of the questions. The plaintiff filed its opening brief on July 1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on October 20, 2022.

The Utility is unable to determine the timing and outcome of this proceeding.

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. In the matter of Santa Cruz County’s complaint with the CPUC, the parties reached a settlement, and the CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, Cal Fire, and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues and to work with Santa Cruz County to implement the terms of the settlement agreement. 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 recorded charges during the fourth quarters of 2021 and 2022, each for an amount that is 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 non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:

			Balance at
(in millions)			December 31, 2022						December 31, 2021
Topock natural gas compressor station			$	284					$	299
Hinkley natural gas compressor station			110						123
Former MGP sites owned by the Utility or third parties (1)			750						667
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)			112						104
Fossil fuel-fired generation facilities and sites (3)			26						70
Total environmental remediation liability			$	1,282					$	1,263

(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, 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 Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances. The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability as of December 31, 2022, 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, 2022, the Utility expected to recover $1.05 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. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $240 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 has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. 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 other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2023. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $126 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. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $511 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. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $51 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. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $50 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 retired Humboldt Bay Unit 3.

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 Unit 3, 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 at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more terrorist acts occurring within a 12-month period at member sites. NEIL also provides coverage for damages caused by cyber events at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more cyber events occurring within a 12-month period at member sites. 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. 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 $13.7 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.7 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 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 Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, 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, 2022:

			Power Purchase Agreements
(in millions)			Renewable Energy						Conventional Energy						Other						Natural Gas						Nuclear Fuel						Total
2023			$	2,081					$	482					$	60					$	1,746					$	47					$	4,416
2024			2,052						378						61						195						11						2,697
2025			2,040						715						61						140						—						2,956
2026			1,980						663						21						129						—						2,793
2027			1,919						579						7						53						—						2,558
Thereafter			17,807						1,565						13						—						—						19,385
Total purchase commitments			$	27,879					$	4,382					$	223					$	2,263					$	58					$	34,805

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, 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 2023 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 2023 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, 2022, QF contracts in operation expire at various dates between 2023 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 $2.8 billion in 2022, $3.0 billion in 2021, and $2.9 billion in 2020.

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 2023 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 $2.4 billion in 2022, $1.2 billion in 2021, and $0.8 billion in 2020.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2023 and 2024 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 $44 million in 2022, $79 million in 2021, and $111 million in 2020.

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 2023 and 2057. At December 31, 2022, the future minimum payments related to these commitments were as follows:

(in millions)			Other Commitments
2023			$	88
2024			85
2025			83
2026			81
2027			80
Thereafter			3,518
Total minimum lease payments			$	3,935

Payments for other commitments were $63 million in 2022, $50 million in 2021, and $45 million in 2020. 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.

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, 2022, 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, 2022.

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, 2022, 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, 2022 and 2021, the related consolidated statements of income, comprehensive income, equity and cash flows, for each of the three years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 22, 2023, 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 3, 4 and 15 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company (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.

We identified the impact of rate regulation 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, as well as likelihood of refunds to customers. 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 that the costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or likely refund as a regulatory liability under GAAP and are recorded at the appropriate amount.

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 and 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 included the following, among others:

• We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets; 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.

• For regulatory matters in process (e.g., applications for cost recovery), 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. For regulatory liabilities, we selected samples of regulatory liabilities and evaluated whether the Company met the definition of a refund or a future reduction in rates.

• We evaluated whether the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies and Recoveries—Refer to Note 15 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. The Company has recorded estimated probable losses of $1,025 million, $400 million, $1,175 million, and $100 million, respectively, as of December 31, 2022, which represents the lower end of the range of reasonably possible losses in connection with each of the fires. The Company has recorded estimated recoveries of wildfire-related contingencies, including $439 million and $175 million, in the Wildfire Expense Memorandum Account (“WEMA”) and Wildfire Fund, respectively, as of December 31, 2022.

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 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 in our procedures.

SB 901 Securitization—Refer to Note 6 to the financial statements

Critical Audit Matter Description

SB 901, signed into law on September 21, 2018, authorized the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (CHT) as defined in SB 901. The CPUC authorized the Utility to establish a customer credit trust funded by the Company’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The Company’s subsidiary, PG&E Wildfire Recovery Funding LLC, securitized $7.5 billion of 2017 wildfire claims costs through the issuance of recovery bonds that is designed to be rate-neutral to its customers. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the 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. 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, 2022.

Also pursuant to the CHT decision, the Utility recorded a SB 901 securitization regulatory asset in the amount of $5.5 billion, 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. The Utility also recorded a SB 901 securitization regulatory liability which represents certain shareholder tax benefits the Utility has recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization expense reflected within Operating and maintenance expense in the Consolidated Statements of Income. At December 31, 2022, the Utility had SB 901 securitization regulatory assets of $5.5 billion and SB 901 securitization regulatory liabilities of $6.1 billion, with SB 901 securitization charges, net recorded on the Consolidated Statement of Income of $608 million.

We identified the accounting for the SB 901 securitization as a critical audit matter due to the significant judgments made by management in the application of the relevant GAAP. This required specialized knowledge of accounting for rate regulation required significant audit effort when performing audit procedures to evaluate the accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the SB 901 securitization included the following:

• We tested the effectiveness of controls over the evaluation of the accounting treatment for the SB 901 securitization and disclosures related to the securitization.

• With the assistance of professionals in our firm having expertise in accounting for rate regulation, we evaluated the conclusions regarding the regulatory asset, regulatory liability, expense and tax accounting treatment applied to the SB 901 securitization by performing the following:

◦Read the terms and conditions included in the financing order, as well as correspondence with the CPUC regarding the intent of the securitization.

◦Evaluated the conclusions regarding the GAAP applied to account for the transaction.

• We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.

Wildfire Fund—Refer to Notes 3 and 14 to the financial statements

Critical Audit Matter Description

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which 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. The Company accounts for the 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 of December 31, 2022, the Wildfire Fund asset is $5.3 billion and the related amortization and accretion for the year ended December 31, 2022 is $477 million. AB 1054 did not specify a period of coverage; therefore the Company estimated the useful life of 15 years using a Monte Carlo simulation.

We identified the Company’s accounting for the Wildfire Fund asset as a critical audit matter due to significant judgments made by management to determine the useful life, specifically the updated assumption related to the effectiveness of wildfire mitigation efforts. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve actuarial specialists when performing audit procedures to evaluate the Company’s accounting and disclosure related to the Wildfire Fund.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Wildfire Fund included the following:

• We tested the effectiveness of controls over (1) the Company’s review of the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts, (2) review of the Monte Carlo simulation methodology used to develop useful life estimate and (3) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.

• With the assistance of our actuarial specialists, we evaluated the appropriateness of the methodology used to determine the Wildfire Fund asset useful life. This evaluation of the modeling methodology included a detailed assessment of the Monte Carlo simulation.

• We evaluated each of management’s key assumptions to the useful life estimate and judgments made by management, including those related to the effectiveness of wildfire mitigation efforts, by inquiring of management, comparing the assumptions to relevant source data, performing sensitivity analyses including information filed with the Company’s regulator related to wildfire mitigation efforts and other publicly available data. Additionally, we inspected relevant source data for any evidence that might contradict management’s assertions.

• We evaluated whether the disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 22, 2023, 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.

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 3, 4, and 15 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.

We identified the impact of rate regulation 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, as well as likelihood of refunds to customers. 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 that the costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or likely refund as a regulatory liability under GAAP and are recorded at the appropriate amount.

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 and 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 included the following, among others:

• We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets 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.

• For regulatory matters in process (e.g., applications for cost recovery), 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. For regulatory liabilities, we selected samples of regulatory liabilities and evaluated whether the Utility met the definition of a refund or a future reduction in rates.

• We evaluated whether the Utility’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.

Wildfire-Related Contingencies and Recoveries—Refer to Note 15 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. The Utility has recorded estimated probable losses of $1,025 million,$400 million, $1,175 million, and $100 million, respectively as of December 31, 2022, which represents the lower end of the range of reasonably possible losses in connection with each of the fires. The Utility has recorded estimated recoveries of wildfire‐related contingencies, including $439 million and $175 million, in the Wildfire Expense Memorandum Account (“WEMA”) and Wildfire Fund, respectively, as of December 31, 2022.

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 in our procedures.

SB 901 Securitization—Refer to Note 6 to the financial statements

Critical Audit Matter Description

SB 901, signed into law on September 21, 2018, authorized the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (CHT) as defined in SB 901. The CPUC authorized the Utility to establish a customer credit trust funded by the Utility’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The Utility’s subsidiary, PG&E Wildfire Recovery Funding LLC, securitized $7.5 billion of 2017 wildfire claims costs through the issuance of recovery bonds that is designed to be rate-neutral to its customers. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the 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. 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, 2022.

Also pursuant to the CHT decision, the Utility recorded a SB 901 securitization regulatory asset in the amount of $5.5 billion, 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. The Utility also recorded a SB 901 securitization regulatory liability which represents certain shareholder tax benefits the Utility has recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization expense reflected within Operating and maintenance expense in the Consolidated Statements of Income. At December 31, 2022, the Utility had SB 901 securitization regulatory assets of $5.5 billion and SB 901 securitization regulatory liabilities of $6.1 billion, with SB 901 securitization charges, net recorded on the Consolidated Statement of Income of $608 million.

We identified the accounting for the SB 901 securitization as a critical audit matter due to the significant judgments made by management in the application of the relevant GAAP. This required specialized knowledge of accounting for rate regulation required significant audit effort when performing audit procedures to evaluate the accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the SB 901 securitization included the following:

• We tested the effectiveness of controls over the evaluation of the accounting treatment for the SB 901 securitization and disclosures related to the securitization.

• With the assistance of professionals in our firm having expertise in accounting for rate regulation, we evaluated the conclusions regarding the regulatory asset, regulatory liability, expense and tax accounting treatment applied to the SB 901 securitization by performing the following:

◦Read the terms and conditions included in the financing order, as well as correspondence with the CPUC regarding the intent of the securitization.

◦Evaluated the conclusions regarding the GAAP applied to account for the transaction.

• We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.

Wildfire Fund—Refer to Notes 3 and 14 to the financial statements

Critical Audit Matter Description

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which 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. The Utility accounts for the 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 of December 31, 2022, the Wildfire Fund asset is $5.3 billion and the related amortization and accretion for the year ended December 31, 2022 is $477 million. AB 1054 did not specify a period of coverage; therefore, the Utility estimated the useful life of 15 years using a Monte Carlo simulation.

We identified the Utility’s accounting for the Wildfire Fund asset as a critical audit matter due to significant judgments made by management to determine the useful life, specifically the updated assumption related to the effectiveness of wildfire mitigation efforts. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve actuarial specialists when performing audit procedures to evaluate the Utility’s accounting and disclosure related to the Wildfire Fund.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Wildfire Fund included the following:

• We tested the effectiveness of controls over (1) the Utility’s review of the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts, (2) review of the Monte Carlo simulation methodology used to develop useful life estimate and (3) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, specifically the update assumption related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.

• With the assistance of our actuarial specialists, we evaluated the appropriateness of the methodology used to determine the Wildfire Fund asset useful life. This evaluation of the modeling methodology included a detailed assessment of the Monte Carlo simulation.

• We evaluated each of management’s key assumptions to the useful life estimate and judgments made by management, including those related to the effectiveness of wildfire mitigation efforts, by inquiring of management, comparing the assumptions to relevant source data, performing sensitivity analyses including information filed with the Utility’s regulator related to wildfire mitigation efforts and other publicly available data. Additionally, we inspected relevant source data for any evidence that might contradict management’s assertions.

• We evaluated whether the disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 22, 2023

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, 2022, 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, 2022, 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, 2022, of the Company and our report dated February 22, 2023, 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 22, 2023

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, 2022, 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, 2022, 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, 2022, of the Utility and our report dated February 22, 2023, 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.

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 22, 2023