Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)


	Year ended December 31,
	2021		2020		2019
Operating Revenues
Electric	$	15,131	$	13,858	$	12,740
Natural gas	5,511		4,611		4,389
Total operating revenues	20,642		18,469		17,129
Operating Expenses
Cost of electricity	3,232		3,116		3,095
Cost of natural gas	1,149		782		734
Operating and maintenance	10,200		8,684		8,725
Wildfire-related claims, net of recoveries	258		251		11,435
Wildfire fund expense	517		413		—
Depreciation, amortization, and decommissioning	3,403		3,468		3,234
Total operating expenses	18,759		16,714		27,223
Operating Income (Loss)	1,883		1,755		(10,094)
Interest income	20		39		82
Interest expense	(1,601)		(1,260)		(934)
Other income, net	457		483		250
Reorganization items, net	(11)		(1,959)		(346)
Income (Loss) Before Income Taxes	748		(942)		(11,042)
Income tax provision (benefit)	836		362		(3,400)
Net Loss	(88)		(1,304)		(7,642)
Preferred stock dividend requirement of subsidiary	14		14		14
Loss Attributable to Common Shareholders	$	(102)	$	(1,318)	$	(7,656)
Weighted Average Common Shares Outstanding, Basic	1,985		1,257		528
Weighted Average Common Shares Outstanding, Diluted	1,985		1,257		528
Net Loss Per Common Share, Basic	$	(0.05)	$	(1.05)	$	(14.50)
Net Loss Per Common Share, Diluted	$	(0.05)	$	(1.05)	$	(14.50)

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	Year ended December 31,
	2021		2020		2019
Net Loss	$	(88)	$	(1,304)	$	(7,642)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $3, $7, and $0, at respective dates)	7		(17)		(1)
Total other comprehensive income (loss)	7		(17)		(1)
Comprehensive Loss	(81)		(1,321)		(7,643)
Preferred stock dividend requirement of subsidiary	14		14		14
Comprehensive Loss Attributable to Common Shareholders	$	(95)	$	(1,335)	$	(7,657)

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)


	Balance at December 31,
	2021		2020
ASSETS
Current Assets
Cash and cash equivalents	$	291	$	484
Restricted Cash	16		143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345		1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207		1,083
Regulatory balancing accounts	2,999		2,001
Other	1,784		1,172
Regulatory assets	496		410
Inventories
Gas stored underground and fuel oil	44		95
Materials and supplies	552		533
Wildfire fund asset	461		464
Other	882		1,334
Total current assets	11,077		9,602
Property, Plant, and Equipment
Electric	69,482		66,982
Gas	25,979		24,135
Construction work in progress	3,479		2,757
Financing lease and other	20		20
Total property, plant, and equipment	98,960		93,894
Accumulated depreciation	(29,134)		(27,758)
Net property, plant, and equipment	69,826		66,136
Other Noncurrent Assets
Regulatory assets	9,207		8,978
Nuclear decommissioning trusts	3,798		3,538
Operating lease right of use asset	1,234		1,741
Wildfire fund asset	5,313		5,816
Income taxes receivable	9		67
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,863		1,978
Total other noncurrent assets	22,424		22,118
TOTAL ASSETS	$	103,327	$	97,856

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)


	Balance at December 31,
	2021		2020
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,184	$	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,481		28
Accounts payable
Trade creditors	2,855		2,402
Regulatory balancing accounts	1,121		1,245
Other	679		580
Operating lease liabilities	468		533
Disputed claims and customer refunds	—		242
Interest payable	481		498
Wildfire-related claims	2,722		2,250
Other	2,436		2,256
Total current liabilities	17,427		13,581
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	38,225		37,288
Regulatory liabilities	11,999		10,424
Pension and other postretirement benefits	860		2,444
Asset retirement obligations	5,298		6,412
Deferred income taxes	3,177		1,398
Operating lease liabilities	810		1,208
Other	4,308		3,848
Total noncurrent liabilities	64,677		63,022
Contingencies and Commitments (Notes 14 and 15)
Equity
Shareholders' Equity
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,985,400,540 and 1,984,678,673 shares outstanding at respective dates	35,129		30,224
Treasury Stock, at cost; 477,743,590 and 0 shares at respective dates	(4,854)		—
Reinvested earnings	(9,284)		(9,196)
Accumulated other comprehensive loss	(20)		(27)
Total shareholders' equity	20,971		21,001
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	21,223		21,253
TOTAL LIABILITIES AND EQUITY	$	103,327	$	97,856

See accompanying Notes to the Consolidated Financial Statements.

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities
Net income (loss)	$	(88)	$	(1,304)	$	(7,642)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403		3,468		3,234
Bad Debt Expense	154		150		46
Allowance for equity funds used during construction	(133)		(140)		(79)
Deferred income taxes and tax credits, net	1,783		1,097		(2,948)
Reorganization items, net (Note 2)	(73)		1,458		108
Wildfire fund expense	517		413		—
Disallowed capital expenditures	—		17		581
Other	248		249		161
Effect of changes in operating assets and liabilities:
Accounts receivable	(589)		(1,182)		(104)
Wildfire-related insurance receivable	(723)		1,564		35
Inventories	(32)		6		(80)
Accounts payable	117		58		516
Wildfire-related claims	472		(16,525)		(114)
Income taxes receivable/payable	—		—		23
Other current assets and liabilities	244		(1,079)		77
Regulatory assets, liabilities, and balancing accounts, net	(2,266)		(2,451)		(1,417)
Liabilities subject to compromise	—		413		12,222
Contributions to Wildfire fund	(193)		(5,200)		—
Other noncurrent assets and liabilities	(579)		(142)		197
Net cash provided by (used in) operating activities	2,262		(19,130)		4,816
Cash Flows from Investing Activities
Capital expenditures	(7,689)		(7,690)		(6,313)
Proceeds from sale of the SFGO	749		—		—
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678		1,518		956
Purchases of nuclear decommissioning trust investments	(1,702)		(1,590)		(1,032)
Other	59		14		11
Net cash used in investing activities	(6,905)		(7,748)		(6,378)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	—		500		1,850
Repayments of debtor-in-possession credit facility	—		(2,000)		(350)
Debtor-in-possession credit facility debt issuance costs	—		(6)		(113)
Bridge facility financing fees	—		(73)		—

Borrowings under credit facilities	9,730		8,554		—
Repayments under credit facilities	(9,976)		(3,949)		—
Credit facilities financing fees	(9)		(22)		—

Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300		1,448		—


Short-term debt matured	(1,450)		—		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $43, $178, and $0 at respective dates	5,474		13,497		—
Repayment of long-term debt	(87)		(764)		—
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		85
Equity Units issued	—		1,304		—
Other	(29)		(40)		(8)
Net cash provided by financing activities	4,323		25,928		1,464
Net change in cash, cash equivalents, and restricted cash	(320)		(950)		(98)
Cash, cash equivalents, and restricted cash at January 1	627		1,577		1,675
Cash, cash equivalents, and restricted cash at December 31	$	307	$	627	$	1,577
Less: Restricted cash and restricted cash equivalents	(16)		(143)		(7)
Cash and cash equivalents at December 31	$	291	$	484	$	1,570


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,404)	$	(1,563)	$	(10)
Income taxes, net	99		—		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,311	$	515	$	826
Operating lease liabilities arising from obtaining ROU assets	100		13		2,816
Common stock issued in satisfaction of liabilities	—		8,276		—
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement	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, 2018	520,338,710	$	12,910	—	$	—	$	(250)	$	(9)	$	12,651	$	252	$	12,903
Net loss	—	—		—	—		(7,642)		—		(7,642)		—		(7,642)
Other Comprehensive loss	—	—		—	—		—		(1)		(1)		—		(1)
Common stock issued, net	8,898,031	85		—	—		—		—		85		—		85
Stock-based compensation amortization	—	43		—	—		—		—		43		—		43
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

(1) Excludes 477,743,590 shares of common stock issued to ShareCo. For more information, see Note 6 below.

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in millions)


	Year ended December 31,
	2021		2020		2019
Operating Revenues
Electric	$	15,131	$	13,858	$	12,740
Natural gas	5,511		4,611		4,389
Total operating revenues	20,642		18,469		17,129
Operating Expenses
Cost of electricity	3,232		3,116		3,095
Cost of natural gas	1,149		782		734
Operating and maintenance	10,194		8,707		8,750
Wildfire-related claims, net of recoveries	258		251		11,435
Wildfire fund expense	517		413		—
Depreciation, amortization, and decommissioning	3,403		3,469		3,233
Total operating expenses	18,753		16,738		27,247
Operating Income (Loss)	1,889		1,731		(10,118)
Interest income	22		39		82
Interest expense	(1,373)		(1,111)		(912)
Other income, net	512		470		239
Reorganization items, net	(12)		(310)		(320)
Income (Loss) Before Income Taxes	1,038		819		(11,029)
Income tax provision (benefit)	900		408		(3,407)
Net Income (Loss)	138		411		(7,622)
Preferred stock dividend requirement	14		14		14
Income (Loss) Available for Common Stock	$	124	$	397	$	(7,636)

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	Year ended December 31,
	2021		2020		2019
Net Income (Loss)	$	138	$	411	$	(7,622)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $1, $2, and $1, at respective dates)	(4)		(6)		2
Total other comprehensive income (loss)	(4)		(6)		2
Comprehensive Income (Loss)	$	134	$	405	$	(7,620)

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)


	Balance at December 31,
	2021		2020
ASSETS
Current Assets
Cash and cash equivalents	$	165	$	261
Restricted Cash	16		143
Accounts receivable
Customers (net of allowance for doubtful accounts of $171 million and $146 million at respective dates) (includes $2.06 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $171 million and $143 million at respective dates)	2,345		1,883
Accrued unbilled revenue (includes $1.09 billion and $959 million related to VIEs at respective dates)	1,207		1,083
Regulatory balancing accounts	2,999		2,001
Other	1,932		1,180
Regulatory assets	496		410
Inventories
Gas stored underground and fuel oil	44		95
Materials and supplies	552		533
Wildfire fund asset	461		464
Other	869		1,321
Total current assets	11,086		9,374
Property, Plant, and Equipment
Electric	69,482		66,982
Gas	25,979		24,135
Construction work in progress	3,480		2,757
Financing lease	18		18
Total property, plant, and equipment	98,959		93,892
Accumulated depreciation	(29,131)		(27,756)
Net property, plant, and equipment	69,828		66,136
Other Noncurrent Assets
Regulatory assets	9,207		8,978
Nuclear decommissioning trusts	3,798		3,538
Operating lease right of use asset	1,232		1,736
Wildfire fund asset	5,313		5,816
Income taxes receivable	7		66
Other (includes net noncurrent accounts receivable of $187 million and $0 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $0 at respective dates)	2,706		1,818
Total other noncurrent assets	22,263		21,952
TOTAL ASSETS	$	103,177	$	97,462

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,
	2021		2020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	2,184	$	3,547
Long-term debt, classified as current (includes $18 million and $0 related to VIEs at respective dates)	4,455		—
Accounts payable
Trade creditors	2,853		2,366
Regulatory balancing accounts	1,121		1,245
Other	648		624
Operating lease liabilities	467		530
Disputed claims and customer refunds	—		242
Interest payable	430		444
Wildfire-related claims	2,722		2,250
Other	2,430		2,248
Total current liabilities	17,310		13,496
Noncurrent Liabilities
Long-term debt (includes $1.82 billion and $1.0 billion related to VIEs at respective dates)	33,632		32,664
Regulatory liabilities	11,999		10,424
Pension and other postretirement benefits	764		2,328
Asset retirement obligations	5,298		6,412
Deferred income taxes	3,409		1,570
Operating lease liabilities	810		1,206
Other	4,345		3,886
Total noncurrent liabilities	60,257		58,490
Contingencies and Commitments (Notes 14 and 15)
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	28,286		28,286
Reinvested earnings	(4,247)		(4,385)
Accumulated other comprehensive loss	(9)		(5)
Total shareholders' equity	25,610		25,476
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	103,177	$	97,462

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year ended December 31,
	2021		2020		2019
Cash Flows from Operating Activities
Net income (loss)	$	138	$	411	$	(7,622)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,403		3,469		3,233
Bad Debt Expense	154		150		46
Allowance for equity funds used during construction	(133)		(140)		(79)
Deferred income taxes and tax credits, net	1,846		1,141		(2,952)
Reorganization items, net (Note 2)	(41)		(90)		97
Wildfire fund expense	517		413		—
Disallowed capital expenditures	—		17		581
Other	172		220		121
Effect of changes in operating assets and liabilities:
Accounts receivable	(584)		(1,160)		(132)
Wildfire-related insurance receivable	(723)		1,564		35
Inventories	(32)		6		(80)
Accounts payable	44		(24)		579
Wildfire-related claims	472		(16,525)		(114)
Income taxes receivable/payable	—		—		5
Other current assets and liabilities	251		(1,141)		101
Regulatory assets, liabilities, and balancing accounts, net	(2,266)		(2,451)		(1,417)
Liabilities subject to compromise	—		401		12,194
Contributions to Wildfire fund	(193)		(5,200)		—
Other noncurrent assets and liabilities	(577)		(108)		214
Net cash provided by (used in) operating activities	2,448		(19,047)		4,810
Cash Flows from Investing Activities
Capital expenditures	(7,689)		(7,690)		(6,313)
Proceeds from sale of the SFGO	749		—		—
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,678		1,518		956
Purchases of nuclear decommissioning trust investments	(1,702)		(1,590)		(1,032)
Intercompany note to PG&E Corporation	(145)		—		—
Other	59		14		11
Net cash used in investing activities	(7,050)		(7,748)		(6,378)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	—		500		1,850
Repayments of debtor-in-possession credit facility	—		(2,000)		(350)
Debtor-in-possession credit facility debt issuance costs	—		(6)		(97)
Bridge facility financing fees	—		(33)		—

Borrowings under credit facilities	9,730		8,554		—
Repayments under credit facilities	(9,976)		(3,949)		—
Credit facilities financing fees	(9)		(22)		—


Short-term debt financing, net of issuance costs of $1, $2, and $0 at respective dates	300		1,448		—
Short-term debt matured	(1,450)		—		—
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $43, $88, and $0 at respective dates	5,474		8,837		—
Repayment of long-term debt	(59)		(100)		—
Proceeds from sale of future revenue from transmission tower license sales, net of fees	370		—		—
Exchanged debt financing fees	—		(103)		—
Equity contribution from PG&E Corporation	—		12,986		—
Other	(1)		(42)		(8)
Net cash provided by financing activities	4,379		26,070		1,395
Net change in cash, cash equivalents, and restricted cash	(223)		(725)		(173)
Cash, cash equivalents, and restricted cash at January 1	404		1,129		1,302
Cash, cash equivalents, and restricted cash at December 31	$	181	$	404	$	1,129
Less: Restricted cash and restricted cash equivalents	(16)		(143)		(7)
Cash and cash equivalents at December 31	$	165	$	261	$	1,122


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,198)	$	(1,458)	$	(7)
Income taxes, net	99		—		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,311	$	515	$	826
Operating lease liabilities arising from obtaining ROU assets	100		13		2,807
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, 2018	$	258	$	1,322	$	8,550	$	2,826	$	(1)	$	12,955
Net loss	—		—		—		(7,622)		—		(7,622)
Other comprehensive income	—		—		—		—		2		2
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

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 the Petition Date, 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.

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 the Petition Date, of which approximately 80,000 were channeled to a trust for the benefit of holders of certain subrogation claims (the “Subrogation Wildfire Trust”) and 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 14 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 14 under the heading “Securities Class Action Litigation.”

In addition to filing objections in the Bankruptcy Court to claims with respect to which PG&E Corporation and the Utility do not believe they have liability, PG&E Corporation and the Utility are working to resolve certain disputed general unsecured claims before a panel of mediators. On November 4, 2021, the Bankruptcy Court entered an order extending the deadline for PG&E Corporation and the Utility to object to claims to June 21, 2022, except for a claim filed by the California Department of Water Resources, for which the Bankruptcy Court set an objection deadline of March 23, 2022.

Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings were pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and recover on the Utility’s refund claims against these electricity suppliers. After the Utility received $145 million from the California Power Exchange and various escrows that were established as part of the disputed claims settlements in December 2021, the Utility filed at the Bankruptcy Court to close out its 2001 bankruptcy case. On December 22, 2021, the Bankruptcy Court granted the motion for entry of final decree and closed the 2001 bankruptcy case. As of December 31, 2021, the Consolidated Balance Sheets reflected $0 in net claims within Disputed claims and customer refunds compared to $242 million as of December 31, 2020. The Utility expects to refund current regulatory liabilities of $422 million, reflected in Current liabilities – other on the Consolidated Balance Sheets, $145 million of which would be funded from the amounts received from the California Power Exchange and various escrows discussed above.

Reorganization Items, Net

Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income and other. Cash paid for reorganization items, net was $31 million and $53 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2021 as compared to $102 million and $400 million for PG&E Corporation and the Utility, respectively, during 2020.

Reorganization items, net for the year ended December 31, 2021 include the following:


	Year Ended December 31, 2021
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	21		(1)		20
Interest and other	(9)		—		(9)
Total reorganization items, net	$	12	$	(1)	$	11

(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

Reorganization items, net for the year ended December 31, 2020 include the following:


	Year Ended December 31, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	6	$	—	$	6
Legal and other (2)	318		1,651		1,969
Interest income	(14)		(2)		(16)
Total reorganization items, net	$	310	$	1,649	$	1,959

(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

(2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees.

Reorganization items, net from the Petition Date through December 31, 2019 include the following:


	Petition Date Through December 31, 2019
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	273		19		292
Interest income	(50)		(10)		(60)
Total reorganization items, net	$	320	$	26	$	346

(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

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, 2020, the Utility also held restricted cash that primarily consisted of cash held in escrow to be used to pay bankruptcy related professional fees.

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. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. 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
(in millions)	2021		2020
Electric
Revenue from contracts with customers
Residential	$	6,089	$	5,523
Commercial	5,042		4,722
Industrial	1,493		1,530
Agricultural	1,565		1,471
Public street and highway lighting	73		69
Other (1)	(84)		(130)
Total revenue from contracts with customers - electric	14,178		13,185
Regulatory balancing accounts (2)	953		673
Total electric operating revenue	$	15,131	$	13,858

Natural gas
Revenue from contracts with customers
Residential	$	2,759	$	2,517
Commercial	713		597
Transportation service only	1,346		1,211
Other (1)	140		61
Total revenue from contracts with customers - gas	4,958		4,386
Regulatory balancing accounts (2)	553		225
Total natural gas operating revenue	5,511		4,611
Total operating revenues	$	20,642	$	18,469

(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, 2021, PG&E Corporation and the Utility have 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 using an analysis of regional unemployment rates.

As of December 31, 2021, the allowance also included the estimated impact of the CAPP which offers financial assistance from the State of California for eligible customers in the form of a credit to the customer’s bill. 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 on January 27, 2022.

As of December 31, 2021, the Utility recorded $209 million of long-term accounts receivables as a result of the CPUC’s June 30, 2021 final decision on bill debt relief which offers financial assistance for eligible customers in the form of a 24-month payment plan.

As of December 31, 2021, expected credit losses of $154 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. At 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 14 below. Wildfire fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of the 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 its available-for-sale debt securities. An impairment may exist if there is an intent to sell or a requirement to sell before recovery of the amortized basis. If such an impairment exists, 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, 2021, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as 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.

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.

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)	2021		2020
Electricity generating facilities (1)	5 to 75	$	11,217	$	12,505
Electricity distribution facilities	10 to 70	37,723		34,902
Electricity transmission facilities	15 to 75	15,516		14,414
Natural gas distribution facilities	20 to 60	14,100		12,962
Natural gas transmission and storage facilities	5 to 66	9,067		8,293
Financing lease		18		18
Construction work in progress		3,480		2,757
General plant and other	5 to 50	7,838		8,041
Total property, plant, and equipment		98,959		93,892
Accumulated depreciation		(29,131)		(27,756)
Net property, plant, and equipment (2)		$	69,828	$	66,136

(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 15 below.

(2) Includes $850 million 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 3.82% in 2021, 3.76% in 2020, and 3.80% in 2019. 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 costs 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 $56 million and $133 million during 2021, $35 million and $140 million during 2020, and $55 million and $79 million during 2019.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2021 and 2020, including nuclear decommissioning obligations:


(in millions)	2021		2020
ARO liability at beginning of year	$	6,412	$	5,854
Liabilities incurred in the current period	—		268
Revision in estimated cash flows	(1,378)		53
Accretion	287		265
Liabilities settled	(23)		(28)
ARO liability at end of year	$	5,298	$	6,412

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.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding. In December 2021, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly decreased its ARO liabilities by $1.4 billion. The adjustment was a result of a decrease in estimated costs based on refinements to the site-specific decommissioning analysis. 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 accrued was $3.9 billion and $5.1 billion at December 31, 2021 and 2020, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $7.6 billion and $10.6 billion at December 31, 2021 and 2020, respectively.

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 or recoverable, respectively, from 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.

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 created in connection with the Receivables Securitization Program (as defined below in Note 5 below) in October 2020 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”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets. As of December 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021 and 2020, the SPV had net accounts receivable of $3.3 billion and $2.6 billion, respectively, and outstanding borrowings of $974 million and $1.0 billion, respectively, under the Receivables Securitization Program.

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 AB 1054, 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. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The recovery bonds are scheduled to pay principal and interest semi-annually on January 15 and July 15 of each year. The final scheduled payment date is July 15, 2046. Amounts owed to bond-holders are included in Long-term debt and Long-term debt, classified as current, on the Consolidated Balance Sheets.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2021, PG&E Recovery Funding LLC has outstanding borrowings of $860 million.

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 at December 31, 2021, 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 and 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 at December 31, 2021, it did not consolidate any of them.

Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054

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 Department of Water Resources 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 contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as HFTDs and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million).

On the Emergence Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. San Diego Gas & Electric Company and Southern California Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020 and 2021, the Utility made its second and third annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility have seven remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage.

As of December 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.1 billion in Other non-current liabilities, $461 million in current assets - Wildfire fund asset, and $5.3 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2021 and December 31, 2020, the Utility recorded amortization and accretion expense of $517 million and $413 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.

AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a five-year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to six years. As of December 31, 2021, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by three years assuming greater effectiveness and would decrease the amortization period by two years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level 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 other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility evaluate all assumptions quarterly, and upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California, and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that a participating utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such acceleration of the amortization of the asset could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. As of December 31, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire and $43 million of accelerated amortization, reflected in Wildfire Fund expense.

Other Accounting Policies

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

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 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 12 below for additional details.

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:


(in millions, net of income tax)	Pension Benefits		Other Benefits		Total
Beginning balance	$	(22)	$	17	$	(5)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively)	(417)		170		(247)
Regulatory account transfer (net of taxes of $155 and $66, respectively)	400		(170)		230
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 $1 and $6, respectively)(1)	2		(15)		(13)
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1)	2		5		7
Net current period other comprehensive loss	(17)		—		(17)
Ending balance	$	(39)	$	17	$	(22)

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

Recognition of Lease Assets and Liabilities

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

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

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, 2021 and 2020.

For the years ended December 31, 2021 and 2020, the Utility made total cash payments, including fixed and variable, of $2.4 billion and $2.5 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. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements.

At December 31, 2021 and 2020, the Utility’s operating leases had a weighted average remaining lease term of 6.04 years and 5.7 years and a weighted average discount rate of 6.1% and 6.2%, 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)	2021		2020
Operating lease fixed cost	$	578	$	679
Operating lease variable cost	1,782		1,852
Total operating lease costs	$	2,360	$	2,531

At December 31, 2021, the Utility’s future expected operating lease payments were as follows:


(in millions)	December 31, 2021
2022	$	533
2023	276
2024	118
2025	111
2026	105
Thereafter	444
Total lease payments	1,587
Less imputed interest	(310)
Total	$	1,277

Sale of Transmission Tower Wireless Licenses

On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers.

The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.

The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market additional attachment locations on up to 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.

In addition, the Utility and SBA entered into a Pipeline Cell Site Transaction Agreement pursuant to which the Utility and SBA established terms and conditions for adding additional cell sites under the License Agreement. Pipeline Cell Sites are locations where the Utility was in the process of locating a new Cell Site for a wireless carrier at the close of the transaction.

In exchange for the exclusive license and entry into the License Agreement, SBA paid the Utility $946 million of the purchase price at the closing. On August 15, 2021, the post-closing period ended, and the final purchase price was $947 million, pursuant to the terms of the Transaction Agreement.

The Utility recorded approximately $370 million of the $947 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $947 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement, represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a third-party discounted cash flow model based on business assumptions and estimates to determine the allocation of the purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are included in Other noncurrent liabilities on the Consolidated Balance Sheets.

The Utility recorded the remaining approximately $471 million ($455 million of which was noncurrent) of the sale proceeds to regulatory liabilities, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices.

The financing obligation is amortized through Electric operating revenue and Interest expense on the Consolidated Statements of Income using the effective interest method and the deferred revenue balance is amortized through Electric operating revenue ratably over the 100-year term.

Recently Adopted Accounting Standards

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. PG&E Corporation and the Utility adopted this ASU on January 1, 2021. 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.

Government Assistance

In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance, which increases the transparency of government assistance including the disclosure of (1) the types of assistance, (2) an entity’s accounting for the assistance, and (3) the effect of the assistance on an entity’s financial statements. PG&E Corporation and the Utility adopted this ASU as of December 31, 2021. 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.

Accounting Standards Issued But Not Yet Adopted

Debt

In August 2020, the 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 on an entity’s own equity. This ASU became effective for PG&E Corporation and the Utility on January 1, 2022 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.

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)	2021		2020
Pension benefits (1)	$	708	$	2,245	Indefinitely
Environmental compliance costs	1,089		1,112		32 years
Utility retained generation (2)	133		181		6 years
Price risk management	216		204		19 years
Unamortized loss, net of gain, on reacquired debt	37		49		23 years
Catastrophic event memorandum account (3)	1,119		842		1 - 3 years
Wildfire expense memorandum account (4)	347		400		TBD years
Fire hazard prevention memorandum account (5)	75		137		1 - 3 years
Fire risk mitigation memorandum account (6)	44		66		1 - 3 years
Wildfire mitigation plan memorandum account (7)	424		390		1 - 3 years
Deferred income taxes (8)	1,849		908		51 years
Insurance premium costs (9)	207		294		3 - 4 years
Wildfire mitigation balancing account (10)	273		156		1 - 3 years
General rate case memorandum accounts (11)	—		376		1 - 2 years
Vegetation management balancing account (12)	1,411		592		1 - 3 years
COVID-19 pandemic protection memorandum accounts (13)	49		84		TBD years
Other	1,226		942		Various
Total long-term regulatory assets	$	9,207	$	8,978

(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, 2021 and 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.

(4) Balance as of December 31, 2021 represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire. Balance as of December 31, 2020 is comprised of incremental wildfire liability insurance premium costs for the period July 26, 2017 through December 31, 2019. 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 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 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through December 31, 2021. 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, 2021. Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.

(11) The GRC memorandum accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered through rates over 22 months, beginning March 1, 2021.

(12) Represents costs from routine vegetation management and EVM activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA for the period January 1, 2020 through December 31, 2021. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.

(13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to certain residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2021, the Utility had recorded an under-collection of $30 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA was in effect. 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.

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

Long-term regulatory liabilities are comprised of the following:


	Balance at December 31,
(in millions)	2021		2020
Cost of removal obligations (1)	$	7,306	$	6,905
Recoveries in excess of AROs (2)	388		458
Public purpose programs (3)	946		948
Employee benefit plans (4)	1,229		995
Transmission tower wireless licenses (5)	446		—
SFGO sale (6)	343		—
Other	1,341		1,118
Total long-term regulatory liabilities	$	11,999	$	10,424

(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 placed 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 11 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 $446 million, $311 million and $135 million will be refunded to FERC and CPUC jurisdiction customers, respectively. See Note 3 above.

(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, beginning in 2022.

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)	2021		2020
Gas distribution and transmission	$	—	$	102
Energy procurement	310		413
Public purpose programs	321		292
Fire hazard prevention memorandum account	50		121
Fire risk mitigation memorandum account	14		33
Wildfire mitigation plan memorandum account	67		161
Wildfire mitigation balancing account	91		27
General rate case memorandum accounts	468		313
Vegetation management balancing account	127		115
Insurance premium costs	605		135
Wildfire expense memorandum account	440		—
Residential uncollectibles balancing accounts	127		—
Other	379		289
Total regulatory balancing accounts receivable	$	2,999	$	2,001


	Payable Balance at December 31,
(in millions)	2021		2020
Electric distribution	$	121	$	55
Electric transmission	24		267
Gas distribution and transmission	83		76
Energy procurement	211		158
Public purpose programs	259		410
Nuclear decommissioning adjustment mechanism	137		—
Other	286		279
Total regulatory balancing accounts payable	$	1,121	$	1,245

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency. The FHPMA tracks costs that protect the public from potential fire hazards. The FRMMA and WMPMA balances track costs that are recoverable within 12 months as requested in the 2020 WMCE application. The WMBA tracks costs associated with wildfire mitigation revenue requirement activities. 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. The VMBA tracks routine and EVM activities. 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, 2021, there was $82 million in insurance premium costs recorded in Current regulatory assets. 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. The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. The nuclear decommissioning adjustment mechanism tracks costs 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, 2021:


(in millions)	Termination Date	Maximum Facility Limit			Loans Outstanding			Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2026	$	4,000	(1)	$	1,885		$	692	$	1,423
Utility term loan credit facility	October 2022 (2)	1,441		(2)	1,441		(2)	—		—
Utility receivables securitization program (3)	September 2023	1,000		(4)	974			—		—		(4)
PG&E Corporation revolving credit facility	June 2024	500			—			—		500
Total credit facilities		$	6,941		$	4,300		$	692	$	1,923

(1) Includes a $1.5 billion letter of credit sublimit.

(2 On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022.

(3) On October 5, 2020, the Utility entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. On September 15, 2021, the Receivables Securitization Program was amended and extended to September 15, 2023. For more information, see “Variable Interest Entities” in Note 3 above.

(4) 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 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. As of December 31, 2021, the Receivables Securitization Program had a maximum borrowing base of $974 million and was fully drawn.

Utility

As previously disclosed, 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.

As previously disclosed, 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.

As previously disclosed, on July 1, 2020, the Utility entered into a $3.0 billion term loan credit agreement (the “Utility Term Loan Credit Agreement”) comprised of 364-day tranche loans in the aggregate principal amount of $1.5 billion (the “364-Day Tranche Loans”) and 18-month tranche loans in the aggregate principal amount of $1.5 billion (the “18-Month Tranche Loans”). As previously disclosed, the 364-Day Tranche Loans were paid in full on March 11, 2021. The 18-Month Tranche Loans had an initial maturity date of January 1, 2022. The Utility borrowed the entire amount of the Utility 364-Day Term Loan Facility and the Utility 18-Month Term Loan Facility on July 1, 2020. The proceeds were used to fund transactions contemplated under the Plan.

On October 29, 2021 and on December 31, 2021, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to October 1, 2022. On February 8, 2022, the Utility amended the Utility Term Loan Credit Agreement to, among other things, extend the maturity date of the 18-Month Tranche Loans to January 1, 2023 for those lenders who consented to such extension; the 18-Month Tranche Loans of the non-consenting lenders in an amount equal to $142.5 million were paid in full as of February 8, 2022. To the extent that any 18-Month Tranche Loans remain outstanding on April 1, 2022, a fee will be due and owing to the lenders holding such 18-Month Tranche Loans.

PG&E Corporation

As previously disclosed, 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.

As previously disclosed, 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.

PG&E Corporation’s obligations under the Corporation Revolving Credit Agreement are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.

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. The intercompany note includes usual and customary provisions for notes of this type. The interest rate on the loan is a variable rate equal to the interest rate applicable to loans under the Corporation Revolving Credit Agreement. Interest is due on the last business day of each month, commencing on August 31, 2021. The proceeds were borrowed to fund debt service obligations of PG&E Corporation. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet.

AB 1054

AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization, pursuant to AB 1054, for a transaction to finance, using securitization, up to $1.19 billion of fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021, with the final amount to be financed based on the capital expenditures incurred by the Utility prior to the securitization transaction. On June 24, 2021, the CPUC issued a financing order authorizing the issuance of up to approximately $1.2 billion of recovery bonds to recover up to $1.19 billion of fire risk mitigation capital expenditures plus an estimated $13.3 million in related upfront financing costs. On July 6, 2021, the financing order became final and non-appealable.

On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. The recovery bonds were issued in three tranches: (1) approximately $266 million with an interest rate of 1.46% and is due July 15, 2033, (2) approximately $160 million with an interest rate of 2.28% and is due January 15, 2038, and (3) approximately $434 million with an interest rate of 2.82% and is due July 15, 2048. The net proceeds were used to fund fire risk mitigation capital expenditures that have been incurred by the Utility and incurred by PG&E Corporation on behalf of the Utility in 2020 and 2021.

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

SB 901

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 and the CPUC’s methodology adopted in the CHT OIR, 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 amounts billed to customers, with the proceeds of the securitization used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. In connection with the proposed transaction, the Utility would retire $6.0 billion of Utility debt. 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. The decision is being challenged by TURN.

Short-Term Debt Issuance

On November 15, 2021, the Utility completed the sale of $300 million aggregate principal amount of Floating Rate First Mortgage Bonds due November 14, 2022. The proceeds, along with the long-term debt proceeds from the First Mortgage Bonds also issued on November 15, 2021, were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021.

Long-Term Debt Issuances and Redemptions

Utility

In March 2021, the Utility issued (i) $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, (ii) $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and (iii) $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s Term Loan Credit Agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement and (iii) general corporate purposes.

In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On November 15, 2021, the Utility completed the sale of (i) $900 million aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 and (ii) an additional $550 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 (the “2031 Bonds”). The 2031 Bonds are part of the same series of debt securities issued by the Utility in March 2021. The proceeds were used for the repayment of the $1.45 billion aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due November 15, 2021. The Utility used the remaining net proceeds for general corporate purposes, including the repayment of approximately $300 million 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, 2021		December 31, 2020
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (1)	$	2,709	$	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 debt issuance costs		(26)		—
Unamortized discount, net of premium and debt issuance costs		(90)		(85)
Total PG&E Corporation Long-Term Debt		4,593		4,624
Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate (2)	500		500
2022	1.75%	2,500		2,500
2023	1.37% - 4.25%	3,575		1,175
2024	3.40% - 3.75%	800		800
2025	3.45% - 3.50%	1,475		1,475
2026	2.95% - 3.15%	2,551		2,551
2027	2.10% - 3.30%	2,550		2,550
2028	3.00% - 4.65%	1,975		1,175
2030	4.55%	3,100		3,100
2031	2.50% - 3.25%	3,000		2,000
2040	3.30% - 4.50%	2,951		2,951
2041	4.20% - 4.50%	700		250
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
Less: current portion, net of debt issuance costs		(2,996)		—
Unamortized discount, net of premium and debt issuance costs		(190)		(182)
Total Utility First Mortgage Bonds		31,816		30,170
Recovery Bonds	1.46% - 2.82%	860		—
Less: current portion		(18)		—
Credit Facilities
Receivables securitization program - Stated Maturity: 2023	variable rate (3)	974		1,000
18-month Term Loan - Stated Maturity: 2022	variable rate (4)	1,441		1,500
Less: current portion		(1,441)		—
Unamortized discount, net of premium and debt issuance costs		—		(6)
Total Utility Long-Term Debt		33,632		32,664
Total PG&E Corporation Consolidated Long-Term Debt		$	38,225	$	37,288

(1) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 3.50% and 5.50%, respectively.

(2) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69% and 1.70%, respectively.

(3) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.30% and 1.57%, respectively.

(4) At December 31, 2021 and 2020, the contractual LIBOR-based interest rate on the term loan was 2.38% and 2.44%, respectively.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2021 are reflected in the table below:



(in millions, except interest rates)	2022			2023			2024			2025			2026			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, 2021	3.50		%	3.50		%	3.50		%	3.50		%	—		%	—		%	3.50		%
Variable rate obligations	$	28		$	28		$	28		$	2,625		$	—		$	—		$	2,709
Utility
Average fixed interest rate	1.75		%	2.26		%	3.60		%	3.47		%	3.10		%	3.90		%	3.49		%
Fixed rate obligations	$	2,500		$	3,575		$	800		$	1,475		$	2,551		$	23,601		$	34,502
Variable interest rate as of December 31, 2021	2.20		%	various (1)			—		%	—		%	—		%	—		%	various (1)
Variable rate obligations	$	1,941		$	974		$	—		$	—		$	—		$	—		$	2,915
Total consolidated debt	$	4,469		$	4,577		$	828		$	4,100		$	2,551		$	25,601		$	42,126

(1) At December 31, 2021, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.30%, 1.69% and 2.38% respectively.

NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION

PG&E Corporation had 1,985,400,540 shares of common stock outstanding at December 31, 2021, which excludes 477,743,590 shares of common stock issued to ShareCo. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2021.

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.

During the year ended December 31, 2021, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement. As of December 31, 2021, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the Internal Revenue Code, 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 an agreement (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 2,463,891,104 shares outstanding as of February 4, 2022, only 1,548,403,924 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 assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 4, 2022 was 2.98% of the outstanding shares. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares.

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

Share Exchange and Tax Matters Agreement

In accordance with the Share Exchange and Tax Matters Agreement, the grantor trust election has been filed.

With the grantor trust election, the Utility’s tax deductions occur as and when the Fire Victim Trust pays the fire victims rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. For PG&E Corporation common stock transferred to the Fire Victim Trust, the amount of the tax deduction 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.

Under the Share Exchange and Tax Matters Agreement, the parties agreed to exchange the 477,743,590 shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan (the “Plan Shares”) for an equal number of newly-issued shares of PG&E Corporation common stock (the “New Shares”). Accordingly, on July 9, 2021, PG&E Corporation issued 477,743,590 New Shares to ShareCo, which has the sole purpose of holding the New Shares in a designated brokerage account to facilitate the exchange process. When the Fire Victim Trust desires to sell any or all of its Plan Shares, the Fire Victim Trust may exchange any number of Plan Shares for a corresponding number of New Shares on a share-for-share basis (without any further consideration payable by either party) and thereafter promptly dispose of the New Shares in one or more transactions with one or more third parties. In the event that the Fire Victim Trust is unable to timely dispose of New Shares under certain circumstances (such shares, the “Nonconforming New Shares”), PG&E Corporation has authorized up to 250,000,000 additional shares of PG&E Corporation common stock, which may be transferred by ShareCo to the Fire Victim Trust on behalf of the Utility, in exchange for the Nonconforming New Shares, following the same procedures as for an exchange of Plan Shares for New Shares. The Plan Shares and any Non-Conforming New Shares exchanged will be held thereafter by the Utility. In the event that the Fire Victim Trust disposes of any share of PG&E Corporation’s common stock subject to the Share Exchange and Tax Matters Agreement without complying with the terms of the agreement, the Fire Victim Trust may be required to make a payment to the Utility designed to compensate the Utility for adverse tax consequences arising from nonconforming sale transactions.

Upon PG&E Corporation’s issuance of the New Shares to ShareCo, PG&E Corporation’s common stock increased by $4.85 billion, the fair value of the shares on July 9, 2021. The increase to common stock is fully offset by the fair value of treasury stock recorded. The issuance of the New Shares did not have an impact on the total number of outstanding common shares as the New Shares are currently held by ShareCo and as such, there was no impact on basic or diluted EPS for the year ended December 31, 2021.

When the Fire Victim Trust notifies the Utility that it intends to sell shares, ShareCo (on behalf of the Utility) will transfer the New Shares to the Fire Victim Trust, and the Fire Victim Trust will transfer the Plan Shares to the Utility. The Utility has no plan or intention to dispose of the Plan Shares at any time. As shares are exchanged with the Fire Victim Trust, the Utility will record the cost of shares and PG&E Corporation’s investment under additional paid in capital and PG&E Corporation’s common stock and treasury stock will decrease by the fair value per share established on July 9, 2021.

As of December 31, 2021, none of the 250,000,000 reserved shares had been issued.

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 March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.

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. As of January 31, 2022, there were $59.1 million of such cumulative and unpaid dividends on the Utility’s preferred stock. 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. 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, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. It is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock.

Long-Term Incentive Plan

The LTIP 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 58,552,722 shares were available for future awards at December 31, 2021.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2021:


(in millions)	2021		2020		2019
Stock Options	$	—	$	3	$	7
Restricted stock units	35		15		21
Performance shares	21		17		22
Total compensation expense (pre-tax)	$	56	$	35	$	50
Total compensation expense (after-tax)	$	40	$	25	$	35

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, 2021, 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 2021 and 2020.

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, 2021.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2021:


	Number of Stock Options	Weighted Average Grant- Date Fair Value		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1	2,221,247	$	7.45		$	—
Granted (1)	—	—			—
Exercised	—	—			—
Forfeited or expired	(25,413)	10.23			—
Outstanding at December 31	2,195,834	7.42		4.33	—
Vested or expected to vest at December 31	2,195,834	7.42		4.33	—
Exercisable at December 31	2,195,834	$	7.42	4.33	$	—

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

Restricted Stock Units

Restricted stock units granted after 2014 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 2021, 2020, and 2019 was $11.01, $9.25, and $18.57, respectively. The total fair value of restricted stock units that vested during 2021, 2020, and 2019 was $19 million, $31 million, and $42 million, respectively. The tax detriment from restricted stock units that vested in 2021 was $11 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, 2021, $81 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 2.19 years.

The following table summarizes restricted stock unit activity for 2021:


	Number of Restricted Stock Units	Weighted Average Grant- Date Fair Value
Nonvested at January 1	890,353	$	23.05
Granted	10,352,117	11.01
Vested	(743,672)	25.20
Forfeited	(408,423)	11.67
Nonvested at December 31	10,090,375	$	11.00

Performance Shares

Performance shares generally will 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 2021, 2020, and 2019 was $11.83, $9.62, and $15.39 respectively. The tax detriment from performance shares that vested in 2021 was $19 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, 2021, $50 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.47 years.

The following table summarizes activity for performance shares in 2021:


	Number of Performance Shares	Weighted Average Grant- Date Fair Value
Nonvested at January 1	7,288,782	$	9.16
Granted	2,714,645	11.83
Vested	—	—
Forfeited (1)	(1,436,418)	11.35
Nonvested at December 31	8,567,009	$	9.64

(1) Includes performance shares that expired with zero value as performance targets were not met.

NOTE 7: PREFERRED STOCK

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

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share. At December 31, 2021 and 2020, 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, 2021, 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, 2021, 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, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022.

NOTE 8: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income (loss) available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2021, 2020, and 2019.


	Year Ended December 31,
(in millions, except per share amounts)	2021		2020		2019
Loss attributable to common shareholders	$	(102)	$	(1,318)	$	(7,656)
Weighted average common shares outstanding, basic	1,985		1,257		528
Add incremental shares from assumed conversions:
Employee share-based compensation	—		—		—
Equity Units	—		—		—
Weighted average common share outstanding, diluted	1,985		1,257		528
Total Loss per common share, diluted	$	(0.05)	$	(1.05)	$	(14.50)

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 9: INCOME TAXES

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

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

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

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

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


	PG&E Corporation						Utility
	Year Ended December 31,
(in millions)	2021		2020		2019		2021		2020		2019
Current:
Federal	$	—	$	(26)	$	1	$	—	$	(26)	$	4
State	1		(34)		101		—		(34)		94
Deferred:
Federal	543		258		(2,361)		588		290		(2,363)
State	296		171		(1,136)		316		185		(1,137)
Tax credits	(4)		(7)		(5)		(4)		(7)		(5)
Income tax provision (benefit)	$	836	$	362	$	(3,400)	$	900	$	408	$	(3,407)

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


	PG&E Corporation				Utility
	Year Ended December 31,
(in millions)	2021		2020		2021		2020
Deferred income tax assets:
Tax carryforwards	$	5,628	$	7,641	$	5,425	$	7,529
Compensation	185		187		108		109
Wildfire-related claims (1)	1,723		544		1,723		544
Operating lease liability	346		489		346		488
Transmission tower wireless licenses	266		—		266		—
Other (2)	278		212		293		219
Total deferred income tax assets	$	8,426	$	9,073	$	8,161	$	8,889
Deferred income tax liabilities:
Property related basis differences	8,847		8,311		8,835		8,300
Regulatory balancing accounts	1,193		763		1,193		763
Debt financing costs	501		526		501		526
Operating lease right of use asset	346		489		346		488
Income tax regulatory asset (3)	517		254		517		254
Other (4)	199		128		178		128
Total deferred income tax liabilities	$	11,603	$	10,471	$	11,570	$	10,459
Total net deferred income tax liabilities	$	3,177	$	1,398	$	3,409	$	1,570

(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 territory over the past several years.

(2) Amounts include benefits, environmental reserve, 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,
	2021		2020		2019		2021		2020		2019
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)	31.3		(15.3)		7.5		24.1		19.1		7.5
Effect of regulatory treatment of fixed asset differences (2)	(71.5)		39.0		2.8		(51.6)		(44.9)		2.8
Tax credits	(1.7)		1.5		0.1		(1.2)		(1.7)		0.1
Fire Victim Trust (3)	127.3		(44.9)		—		91.9		51.7		—
Bankruptcy and emergence	—		(37.6)		—		—		2.4		—
Other, net (4)	5.3		(2.1)		(0.6)		2.6		2.2		(0.5)
Effective tax rate	111.7	%	(38.4)	%	30.8	%	86.8	%	49.8	%	30.9	%

(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 2021, 2020, and 2019, 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 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 TCC RSA 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 2021 and 2020 as well as a permanent non-deductible equity backstop premium expense in 2020. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively in 2020, accounts for the remaining difference.

(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs in 2021 and 2020.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:


	PG&E Corporation						Utility
(in millions)	2021		2020		2019		2021		2020		2019
Balance at beginning of year	$	437	$	420	$	377	$	437	$	420	$	377
Reductions for tax position taken during a prior year	(23)		(43)		(1)		(23)		(43)		(1)
Additions for tax position taken during the current year	85		60		44		85		60		44
Settlements	(1)		—		—		(1)		—		—
Balance at end of year	$	498	$	437	$	420	$	498	$	437	$	420

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2021 for PG&E Corporation and the Utility was $30 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months.

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, 2021, 2020, and 2019, 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.

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.

Carryforwards

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


(in millions)	December 31, 2021		Expiration Year
Federal:
Net operating loss carryforward - Pre-2018	$	3,600	2031 - 2036
Net operating loss carryforward - Post-2017	17,467		N/A
Tax credit carryforward	144		2029 - 2041

State:
Net operating loss carryforward	$	18,853	2039 - 2041
Tax credit carryforward	122		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

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. At December 31, 2021, it is reasonably possible that within the next 12 months, unrecognized tax benefits will decrease. The amount is not expected to be material.

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 Internal Revenue Code.

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.

During June 2020, the State of California enacted AB 85, which increases taxes on corporations over a three-year period beginning in 2020 by suspension of the net operating loss deduction and a limit of $5 million per year on business tax credits. PG&E Corporation and the Utility do not anticipate any material impacts to PG&E Corporation’s Consolidated Financial Statements due to this legislation.

Additionally, as a result of the grantor trust election, the Utility’s tax deductions occur when the Fire Victim Trust pays the fire victims, rather than when the Utility transferred cash and other property (including PG&E Corporation common stock) to the Fire Victim Trust. Therefore, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion, that were transferred to the Fire Victim Trust in 2020, will not be deductible for tax purposes by the Utility until the Fire Victim Trust pays the fire victims. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. PG&E Corporation’s net operating loss has decreased by approximately $10.0 billion, which will be offset by payments made by the Fire Victim Trust to the fire victims (which totaled approximately $1.67 billion in 2021) and the net activities of the Fire Victim Trust to date. Additionally, there was a $1.3 billion charge, net of tax, decreasing net DTAs for the payment made to the Fire Victim Trust in PG&E Corporation common stock on its Consolidated Financial Statements for activity through December 31, 2020. 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. As of December 31, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock, resulting in no tax impact in PG&E Corporation’s and the Utility’s consolidated financial statements for the year ended December 31, 2021. On January 31, 2022, the Fire Victim Trust initiated an exchange of 40,000,000 Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement and announced that it had entered into a transaction for the sale of these shares. For more information, see Note 6 above.

NOTE 10: DERIVATIVES

Use of Derivative Instruments

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

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

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

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

Volume of Derivative Activity

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


		Contract Volume
		At December 31,
Underlying Product	Instruments	2021	2020
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	173,361,635	146,642,863
	Options	14,420,000	14,140,000
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	10,283,639	9,435,830
	Options	288,000	—
	Congestion Revenue Rights (3)	239,857,610	266,091,470

(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

At 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

At December 31, 2020, 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	$	33	$	—	$	115	$	148
Other noncurrent assets – other	136		—		—		136
Current liabilities – other	(38)		—		15		(23)
Noncurrent liabilities – other	(204)		—		10		(194)
Total commodity risk	$	(73)	$	—	$	140	$	67

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, 2021, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

NOTE 11: FAIR VALUE MEASUREMENTS

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

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

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

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


	Fair Value Measurements
	At December 31, 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.


	Fair Value Measurements
	At December 31, 2020
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	470	$	—	$	—	$	—	$	470
Nuclear decommissioning trusts
Short-term investments	27		—		—		—		27
Global equity securities	2,398		—		—		—		2,398
Fixed-income securities	924		835		—		—		1,759
Assets measured at NAV	—		—		—		—		25
Total nuclear decommissioning trusts (2)	3,349		835		—		—		4,209
Price risk management instruments (Note 10)
Electricity	—		2		166		2		170
Gas	—		1		—		113		114
Total price risk management instruments	—		3		166		115		284
Rabbi trusts
Fixed-income securities	—		106		—		—		106
Life insurance contracts	—		79		—		—		79
Total rabbi trusts	—		185		—		—		185
Long-term disability trust
Short-term investments	9		—		—		—		9
Assets measured at NAV	—		—		—		—		158
Total long-term disability trust	9		—		—		—		167
TOTAL ASSETS	$	3,828	$	1,023	$	166	$	115	$	5,315
Liabilities:
Price risk management instruments (Note 10)
Electricity	—		1		238		(25)		214
Gas	—		3		—		—		3
TOTAL LIABILITIES	$	—	$	4	$	238	$	(25)	$	217

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

(2) Represents amount before deducting $671 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, 2021 and 2020.

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 and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at 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 to net income resulting from changes in the fair value of these instruments. See Note 10 above.


	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 megawatt-hour.

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


	Fair Value at
(in millions)	At December 31, 2020				Valuation Technique	Unobservable Input
Fair Value Measurement	Assets		Liabilities			Range (1)/Weighted-Average Price (2)
Congestion revenue rights	$	153	$	74	Market approach	CRR auction prices	$ (320.25) - 320.25 / 0.30
Power purchase agreements	$	13	$	164	Discounted cash flow	Forward prices	$ 12.56 - 148.30 / 35.52

(1) Represents price per megawatt-hour.

(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, 2021 and 2020, respectively:


	Price Risk Management Instruments
(in millions)	2021		2020
Asset (liability) balance as of January 1	$	(72)	$	5
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	38		(77)
Asset (liability) balance as of December 31	$	(34)	$	(72)

(1) The costs related to price risk management activities are fully passed through to customers in 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 at December 31, 2021 and 2020, 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,
	2021				2020
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 5)
PG&E Corporation	$	4,619	$	4,796	$	1,901	$	2,175
Utility	31,816		35,803		29,664		32,632

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, 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
As of December 31, 2020
Nuclear decommissioning trusts
Short-term investments	$	27	$	—	$	—	$	27
Global equity securities	543		1,881		(1)		2,423
Fixed-income securities	1,610		152		(3)		1,759
Total (1)	$	2,180	$	2,033	$	(4)	$	4,209

(1) Represents amounts before deducting $783 million and $671 million at December 31, 2021 and 2020, 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, 2021
Less than 1 year	$	97
1–5 years	495
5–10 years	480
More than 10 years	952
Total maturities of fixed-income securities	$	2,024

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


(in millions)	2021		2020		2019
Proceeds from sales and maturities of nuclear decommissioning investments	$	1,678	$	1,518	$	956
Gross realized gains on securities	286		159		69
Gross realized losses on securities	(19)		(41)		(14)

NOTE 12: EMPLOYEE BENEFIT PLANS

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

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

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

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2021 and 2020:

Pension Plan


(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	20,759	$	18,547
Actual return on plan assets	1,693		2,736
Company contributions	335		343
Benefits and expenses paid	(892)		(867)
Fair value of plan assets at end of year	$	21,895	$	20,759

Change in benefit obligation:
Benefit obligation at beginning of year	$	23,172	$	20,525
Service cost for benefits earned	587		530
Interest cost	645		713
Actuarial (gain) loss (1)	(752)		2,271
Plan amendments	—		—
Benefits and expenses paid	(893)		(867)
Benefit obligation at end of year (2)	$	22,759	$	23,172

Funded Status:
Current liability	$	(9)	$	(3)
Noncurrent liability	(856)		(2,410)
Net liability at end of year	$	(865)	$	(2,413)

(1) The actuarial gain for the year ended 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. The actuarial loss for the year ended December 31, 2020 was due to a decrease in the discount rate used to measure the projected benefit obligation.

(2) PG&E Corporation’s accumulated benefit obligation was $20.4 billion and $20.7 billion at December 31, 2021 and 2020, respectively.

Postretirement Benefits Other than Pensions


(in millions)	2021		2020
Change in plan assets:
Fair value of plan assets at beginning of year	$	2,995	$	2,678
Actual return on plan assets	193		379
Company contributions	10		26
Plan participant contribution	80		81
Benefits and expenses paid	(176)		(169)
Fair value of plan assets at end of year	$	3,102	$	2,995

Change in benefit obligation:
Benefit obligation at beginning of year	$	1,876	$	1,832
Service cost for benefits earned	63		61
Interest cost	51		63
Actuarial gain (1)	(152)		(14)
Benefits and expenses paid	(156)		(149)
Federal subsidy on benefits paid	4		3
Plan participant contributions	80		80
Benefit obligation at end of year	$	1,766	$	1,876

Funded Status: (2)
Noncurrent asset	$	1,340	$	1,153
Noncurrent liability	(4)		(34)
Net asset at end of year	$	1,336	$	1,119

(1) 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. The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation.

(2) At December 31, 2021 and 2020, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $363 million and $359 million as of December 31, 2021, and $377 million and $343 million as of December 31, 2020, respectively.

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

Components of Net Periodic Benefit Cost

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

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

Pension Plan


(in millions)	2021		2020		2019
Service cost for benefits earned (1)	$	587	$	530	$	443
Interest cost	645		713		758
Expected return on plan assets	(1,046)		(1,044)		(906)
Amortization of prior service cost	(6)		(6)		(6)
Amortization of net actuarial loss	6		3		3
Net periodic benefit cost	186		196		292
Less: transfer to regulatory account (2)	147		136		42
Total expense recognized	$	333	$	332	$	334

(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)	2021		2020		2019
Service cost for benefits earned (1)	$	63	$	61	$	56
Interest cost	51		63		76
Expected return on plan assets	(137)		(138)		(123)
Amortization of prior service cost	14		14		14
Amortization of net actuarial loss	(33)		(21)		(3)
Net periodic benefit cost	$	(42)	$	(21)	$	20

(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,
	2021		2020		2019		2021	2020	2019
Discount rate	3.03	%	2.77	%	3.46	%	2.97 - 3.04%	2.67 - 2.80 %	3.37 - 3.47%
Rate of future compensation increases	3.80	%	3.80	%	3.90	%	N/A	N/A	N/A
Expected return on plan assets	5.50	%	5.10	%	5.70	%	3.30 - 6.40%	3.10 - 6.10 %	3.50 - 6.60%
Interest crediting rate for cash balance plan	1.95	%	1.95	%	2.11	%	N/A	N/A	N/A

The assumed health care cost trend rate as of December 31, 2021 was 6.0%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 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 5.5% compares to a ten-year actual return of 9.6%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 817 Aa-grade non-callable bonds at December 31, 2021. 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 fixed income/equity allocation 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
	2022		2021		2020		2022		2021		2020
Global equity securities	30	%	30	%	30	%	26	%	36	%	28	%
Absolute return	2	%	2	%	2	%	1	%	1	%	2	%
Real assets	8	%	8	%	8	%	3	%	5	%	8	%
Fixed-income securities	60	%	60	%	60	%	70	%	58	%	62	%
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, 2021 and 2020.


	Fair Value Measurements
	At December 31,
	2021								2020
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension Plan:
Short-term investments	$	552	$	255	$	—	$	807	$	334	$	408	$	—	$	742
Global equity securities	2,074		424		—		2,498		1,875		—		—		1,875
Absolute Return	—		1		—		1		1		1		—		2
Real assets	632		—		—		632		517		—		—		517
Fixed-income securities	2,729		7,388		27		10,144		2,467		7,154		12		9,633
Assets measured at NAV	—		—		—		7,972		—		—		—		8,224
Total	$	5,987	$	8,068	$	27	$	22,054	$	5,194	$	7,563	$	12	$	20,993
PBOP Plans:
Short-term investments	$	31	$	—	$	—	$	31	$	37	$	—	$	—	$	37
Global equity securities	105		—		—		105		173		—		—		173
Real assets	34		—		—		34		54		—		—		54
Fixed-income securities	776		875		1		1,652		481		715		1		1,197
Assets measured at NAV	—		—		—		1,296		—		—		—		1,549
Total	$	946	$	875	$	1	$	3,118	$	745	$	715	$	1	$	3,010
Total plan assets at fair value							$	25,172							$	24,003

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $175 million and $249 million at December 31, 2021 and 2020, 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, 2021 and 2020.

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, 2021 and 2020:


(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

(in millions)
For the year ended December 31, 2020	Fixed-Income
Balance at beginning of year	$	15
Actual return on plan assets:
Relating to assets still held at the reporting date	2
Relating to assets sold during the period	(3)
Purchases, issuances, sales, and settlements:
Purchases	11
Settlements	(13)
Balance at end of year	$	12

There were no material transfers out of Level 3 in 2021 and 2020.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $335 million to the pension benefit plans and $10 million to the other benefit plans in 2021. 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 2021. The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2022.

Benefits Payments and Receipts

As of December 31, 2021, 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
2022	869	81	(3)
2023	954	85	(3)
2024	988	89	(3)
2025	1018	88	(3)
2026	1,046	91	(3)
Thereafter in the succeeding five years	5,533	466	(3)

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 Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide 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 $133 million, $119 million, and $109 million in 2021, 2020, and 2019, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

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

NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS

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

The Utility’s significant related party transactions were:


	Year Ended December 31,
(in millions)	2021		2020		2019
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	3	$	4
Utility expenses from:
Administrative services received from PG&E Corporation	$	82	$	108	$	107
Utility employee benefit due to PG&E Corporation	39		34		42

At December 31, 2021 and 2020, the Utility had receivables of $173 million and $35 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 $19 million and $46 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. As of December 31, 2021, the intercompany note is reflected in Accounts receivable - other on the Utility’s Consolidated Balance Sheet and is eliminated upon consolidation of PG&E Corporation’s Consolidated Balance Sheet. For more information, see “Intercompany Note Payable” in Note 5 above.

NOTE 14: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. 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. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses 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 (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. 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.

The process for estimating losses associated with potential claims related to wildfires requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. 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.

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.

Criminal charges have been filed against the Utility in connection with the 2019 Kincade fire and the 2020 Zogg fire. 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. In the event that the Utility were convicted of certain charges in connection with the 2019 Kincade fire or 2020 Zogg fire, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with such fire would 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 currently 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 courts presiding over the criminal proceedings.

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.

PG&E Corporation and the Utility currently 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 proceedings initiated against the Utility. 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 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 territory 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 filed the Kincade Complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Kincade Complaint. It further announced that it would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the Kincade Complaint. At a hearing on September 9, 2021, the Sonoma County Superior Court overruled the demurrer. The Utility pled not guilty to all charges on October 13, 2021. On January 28, 2022, the Sonoma County District Attorney’s Office filed the Kincade Amended Complaint, which replaces two felonies with five different felonies and drops six misdemeanor counts. On January 28, 2022, the court deemed the Utility’s demurrer and the court’s prior ruling as applying to 22 of the 30 counts in the Kincade Amended Complaint, and the Utility thereafter pled not guilty to all charges in the Kincade Amended Complaint. A preliminary hearing on the charges began on February 8, 2022.

On December 2, 2021, the CPUC approved a settlement between the Safety Enforcement Division 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 (i) the Utility will pay $40 million to California’s General Fund; (ii) the Utility will remove permanently abandoned transmission lines over a ten-year period; and (iii) the Utility must incur $85 million of the costs of such work by December 31, 2024, and it may not seek recovery of this $85 million of costs. 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 connection with the Kincade SED Settlement, PG&E Corporation and the Utility recorded a liability of $40 million reflected in Other current liabilities on the Consolidated Financial Statements for the period ended December 31, 2021. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility expects to record such disallowances in 2022. On January 10, 2022, TURN filed an application for rehearing of the Kincade SED Settlement. On January 25, 2022, the Utility filed an opposition to the application for rehearing.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 2,605 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. In addition, on January 5, 2022, Cal Fire filed a complaint in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. Following a November 5, 2021 hearing, the San Francisco County Superior Court set a trial date of November 7, 2022.

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 $625 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of PG&E Corporation’s and the Utility’s Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain subrogation entities, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance).

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 2019 Kincade fire since December 31, 2019.


Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	625
Payments	—
Balance at December 31, 2020	625
Accrued Losses	175
Payments	(31)
Balance at December 31, 2021	$	769

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, 2021, the Utility has recorded an insurance receivable for the full amount of the $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 territory 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 filed the Zogg Complaint charging 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 in the Zogg Complaint. 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 contained in the Zogg Complaint. A hearing on the demurrer is set for April 4, 2022.

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 3, 2022, PG&E Corporation and the Utility are aware of approximately 21 complaints on behalf of at least 382 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. At an October 4, 2021 hearing, the San Francisco County Superior Court set a trial date of February 6, 2023. In addition, PG&E Corporation and the Utility have been contacted by Cal Fire to accept service of a complaint filed against them for fire suppression costs incurred in connection with the 2020 Zogg 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 2020 Zogg fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on the facts and circumstances available to the Utility as of the filing of the Consolidated Financial Statements for the year ended December 31, 2021, including the status of negotiations with certain agencies, subrogation entities, and individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge in 2021 for potential losses in connection with the 2020 Zogg fire in the amount of $100 million, for an aggregate liability of $375 million (before available insurance). Following continued negotiations during the quarter ended December 31, 2021, PG&E Corporation and the Utility entered agreements with all but one of the insurance subrogation plaintiffs in the 2020 Zogg fire litigation to resolve their claims arising from the 2020 Zogg fire.

The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2019.


Loss Accrual (in millions)
Balance at December 31, 2019	$	—
Accrued Losses	275
Payments	—
Balance at December 31, 2020	275
Accrued Losses	100
Payments	(164)
Balance at December 31, 2021	$	211

The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. As of December 31, 2021, the Utility has recorded an insurance receivable for $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $22 million in legal fees incurred. Recovery under the Utility’s insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount.

2021 Dixie Fire

According to Cal Fire, on July 13, 2021, at approximately 5:15 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service territory of the Utility. According to a Cal Fire incident update, dated October 25, 2021, 7:46 a.m. Pacific Time, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,329 structures destroyed (including 717 residential, 143 commercial, and 443 other structures), 95 structures damaged, and one fatality, which according to published reports was a fire fighter who passed away due to COVID-19 after returning home from 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.

The Butte County, Plumas County, Shasta County, Lassen County and Tehama County District Attorneys’ Offices, as well as the SED and OEIS, are 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. 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 2021 Dixie fire. This investigation is ongoing, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.

As of February 3, 2022, PG&E Corporation and the Utility are aware of approximately 20 complaints on behalf of at least 1,005 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.

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 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 due to the incomplete information available to PG&E Corporation and the Utility as of the date of this filing as to facts pertinent to potential claims and defenses. Moreover, PG&E Corporation and the Utility are currently 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 National Interagency Coordination Center Incident Management Situation Report dated October 29, 2021 at 7:30 a.m. Mountain Time, over $630 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility currently estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The Utility has liability insurance coverage for third-party liability attributable to periods in which both the 2020 Zogg fire and 2021 Dixie fire occurred in an aggregate amount of $900 million. Recovery under the Utility’s insurance policies for the 2020 Zogg fire will reduce the amount of insurance proceeds available for the 2021 Dixie fire by the same amount. An immaterial decrease was recorded in the fourth quarter of 2021. As of December 31, 2021, the Utility has recorded an insurance receivable of $563 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 $337 million insurance receivable recorded in connection with the 2020 Zogg fire.

As of December 31, 2021, the Utility has recorded a Wildfire Fund receivable of $150 million for probable recoveries in connection with the 2021 Dixie fire. See “Wildfire Fund under AB 1054” below. The Utility has also recorded a $101 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 $347 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. An immaterial increase was recorded in the fourth quarter of 2021.

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 insurance recoveries.

Total probable recoveries for the 2021 Dixie fire as of December 31, 2021 are:


Potential Recovery Source (in millions)	2021 Dixie fire
Insurance	$	563
FERC TO rates	101
WEMA	347
Wildfire Fund	150
Probable recoveries at December 31, 2021	$	1,161

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 herein, 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 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period from April 13, 2021 to April 1, 2022, and approximately $32 million in incremental wildfire liability reinsurance for the period from April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire liability reinsurance for the period from July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period from August 1, 2020 to August 1, 2021. On August 1, 2021, the $600 million of existing wildfire liability coverage renewed on a 12-month term covering the period from August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million.

In June 2021, the Utility purchased approximately $535 million in non-wildfire liability coverage for the period from June 1, 2021 to April 1, 2022 at a cost of approximately $89 million. This coverage is in addition to approximately $140 million in existing non-wildfire liability insurance for the period from August 1, 2020 to August 1, 2021. In connection with the June 2021 renewal, the Utility procured an extension of this existing coverage to April 1, 2022 at a premium cost of approximately $30 million. The Utility also has $50 million in additional non-wildfire liability coverage available through one of its wildfire liability policies with shared limits. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million. As of December 31, 2021, PG&E Corporation and the Utility had prepaid insurance of $358 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 general liability insurance coverage. For more information about the RTBA, see Note 4 above.

Insurance Receivable

Through December 31, 2021, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, $337 million for probable insurance recoveries in connection with the 2020 Zogg fire, and $563 million for probable insurance recoveries in connection with the 2021 Dixie fire. 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)	2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	—	$	—	$	1,380	$	808	$	50	$	2,238
Accrued insurance recoveries	—		219		430		—		—		—		649
Reimbursements	—		—		—		(1,380)		(783)		(50)		(2,213)
Balance at December 31, 2020	—		219		430		—		25		—		674
Accrued insurance recoveries (1)	563		118		—		—		—		—		681
Reimbursements (2)	—		(67)		(16)		—		(25)		—		(108)
Balance at December 31, 2021	$	563	$	270	$	414	$	—	$	—	$	—	$	1,247

(1) During the fourth quarter of 2021, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase for the 2020 Zogg fire for $6.5 million.

(2) On January 26, 2022, the Utility received $43 million of insurance reimbursements related to the 2020 Zogg fire.

Regulatory Recovery

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through the FERC TO formula rate in future rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. 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, for the year ended December 31, 2021, the Utility recorded a $101 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.

WEMA

In June 2018, the CPUC approved the establishment of the WEMA, which provides for tracking of incremental wildfire claims and outside legal costs plus incremental insurance premium costs above what is being recovered through rates. For the year ended December 31, 2021, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire were determined to be probable of recovery and the Utility recorded a $347 million regulatory asset in the WEMA.

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, 2021 reflects an expectation that the Coverage Year will be based on the calendar year with coverage limited to the 2021 Dixie Fire. For 2022, PG&E Corporation and the Utility have elected a Coverage Year that commences on January 1, 2022 at 12:01 a.m. Pacific Time and ends on December 31, 2022 at 12:00 a.m. Pacific Time.

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 applying the prudency standard in AB 1054, not to be just and reasonable, 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 $2.9 billion based on its 2021 equity rate base, and 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 fails 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. The Utility expects that the same prudency standard would also be applied in any CPUC review of an application filed by the Utility seeking recovery of costs recorded to the WEMA.

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. On January 14, 2021, the OEIS (then the Wildfire Safety Division of the CPUC) approved the Utility’s 2020 application and issued the Utility’s 2020 safety certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On January 31, 2022, the OEIS approved the Utility’s 2021 application and issued the Utility’s 2021 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 Department of Water Resources 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. For more information see “Initial and Annual Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 3 above.

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, 2021, PG&E Corporation and the Utility recorded $150 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information see Note 3 above.

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 are 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. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions related to the 2017 Northern California wildfires and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, 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 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. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action. The assignment became effective as of the Emergence Date. On November 12, 2020, the trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter, to which the parties later stipulated. On March 8, 2021, the court granted the parties’ stipulation 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 February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. 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 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 is 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. On November 8, 2021, the Court entered an order sustaining in part and overruling in part the demurrers. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint. Trial is set for June 27, 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. A stipulation and proposed order to voluntarily dismiss this action was filed on April 20, 2021 and a case management conference on the dismissal order is set for March 9, 2022.

The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.

Securities Class Action Litigation

Wildfire-Related Securities Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California (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 related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. 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.

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 names 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 is named as a defendant. The complaint alleges 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. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. 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. The securities actions have been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with any such claims submitted through a proof of claim to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases. On April 29, 2021, the District Court issued a notice of intent to stay this action pending completion of the claims procedures in the bankruptcy proceedings. PERA filed objections to the notice of intent to stay on May 28, 2021. PG&E Corporation and the Utility filed a response to PERA’s objections on June 10, 2021, the officer, director, and underwriter defendants filed a response to PERA’s objections on June 11, 2021, and PERA filed a sur-response on June 21, 2021. The District Court has not taken further action with respect to its notice of intent to stay.

Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility 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, will be resolved 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 been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled, PG&E Corporation and the Utility expect that the 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 (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Emergence Date).

The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. PERA has filed two motions seeking approval from the Bankruptcy Court to treat its proof of claim as a class claim. On February 27, 2020 and January 26, 2021, the Bankruptcy Court issued orders denying the motions. PERA filed an appeal of the February 27, 2020 order and on March 8, 2021, the District Court issued an order dismissing the appeal.

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 Ninth Circuit Court of Appeals and on December 15, 2021, PERA filed its opening brief. PERA’s appeal to the Ninth Circuit 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. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

PG&E Corporation and the Utility have been working to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by requesting 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.

Based on discussions with certain holders of the HoldCo Rescission or Damage Claims, PG&E Corporation believes it is probable that it will incur a loss in connection with the HoldCo Rescission or Damage Claims. As of the date of this filing, PG&E Corporation determined that the amount or range of such loss is not reasonably estimable because either a negotiated resolution would be contingent upon available insurance coverage, the scope of which has not yet been agreed, or any negotiated resolutions would be limited to a subset of immaterial claims. PG&E Corporation is further unable to estimate the amount or range of loss because the nature and value of HoldCo Rescission or Damage Claims varies significantly among potential claimholders, and as of the date of this filing, PG&E Corporation has only engaged in substantive discussions with a limited subset of claimholders.

PG&E Corporation and the Utility continue to believe it is reasonably possible that they will incur a loss in connection with the Subordinated Debt Claims but are unable to reasonably estimate the amount or range of loss because the nature and value, if any, of such claims varies significantly among potential claimholders. As of December 31, 2021, PG&E Corporation and the Utility have not recorded a liability in connection with the Subordinated Claims.

De-energization Securities Class Action

On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a then-current director and certain then-current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s PSPS events, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint 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, attorneys’ fees and other costs.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a current officer of PG&E Corporation as defendants, and removed claims against certain current and former officers of PG&E Corporation previously named in the action.

On February 16, 2021, the plaintiffs filed a motion with the District Court for preliminary approval of a proposed settlement. On November 2, 2021, the District Court entered an order granting final approval of the settlement, which is now effective. Pursuant to the settlement stipulation: (1) PG&E Corporation paid $10 million, and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) released the Released Persons (as defined in the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulation of settlement.

Indemnification Obligations and Directors’ and Officers’ 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 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 directors’ and officers’ 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 the carriers regarding, among other things, the applicability of multiple years of directors’ and officers’ insurance policies to those matters. Recovery under the directors’ and officers’ insurance policies in one such litigation matter will impact the directors’ and officers’ insurance proceeds available in the other matters.

On March 17, 2021, the trustee for the Fire Victim Trust filed a lawsuit entitled Trotter v. PG&E Corporation, et al., in San Francisco Superior Court, seeking, among other things, a declaration that the trustee for the Fire Victim Trust be permitted to participate in the arbitration with the carriers. The trustee named PG&E Corporation, the Utility, and the insurance carriers as defendants. On March 25, 2021, PG&E Corporation and the Utility removed the action to the Bankruptcy Court. On March 29, 2021, the Fire Victim Trust filed a motion to remand the lawsuit back to state court, which the Bankruptcy Court denied on April 20, 2021. On April 30, 2021, the Fire Victim Trust moved for summary judgment. Oppositions and cross-motions to the summary judgment motion were filed by PG&E Corporation, the Utility and the insurance carriers on May 21, 2021. On June 22, 2021, the Bankruptcy Court entered an order denying the Fire Victim Trust’s motion for summary judgment and granting the defendants’ cross-motions for summary judgment. On June 29, 2021, the Bankruptcy Court entered judgment in favor of all defendants and against the Fire Victim Trust.

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.

The extent of PG&E Corporation’s and the Utility’s recovery of the directors’ and officers’ insurance proceeds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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 Court continued the hearing to February 25, 2022.

Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.40 billion in cash that was contributed on the Emergence Date, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million that was paid in cash on January 18, 2022, in each case pursuant to the terms of the tax benefits payment agreement between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Emergence Date, subject to potential adjustments.

NOTE 15: OTHER CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The 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 and the Utility have financial commitments described in “Other 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.

Enforcement Matters

U.S. District Court Matters and Probation

In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California had the ability to impose additional probation conditions on the Utility. On January 25, 2022, the period of probation expired.

CPUC and FERC Matters

Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire

On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code, Commission General Orders or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.

As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and the Coalition of California Utility Employees jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. The settlement agreement became effective on the Emergence Date.

Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility recorded $1.625 billion of the disallowed costs for the year ended December 31, 2020.


(in millions)
Description (1)	Expense		Capital		Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)	$	236	$	—	$	236
Transmission Safety Inspections and Repairs Expense (TO) (2)	433		—		433
Vegetation Management Support Costs (FHPMA)	36		—		36
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)	82		66		148
2018 Camp Fire CEMA Expense (CEMA)	435		—		435
2018 Camp Fire CEMA Capital for Restoration (CEMA)	—		253		253
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)	—		84		84
Total	$	1,222	$	403	$	1,625

(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.

(2) Transmission amounts are under the FERC’s regulatory authority.

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 and the amount of disallowance can be reasonably estimated.

The Utility expects additional system enhancement spending pursuant to the settlement agreement to occur through 2025.

On April 20, 2020, the assigned commissioner issued a decision different adopting, with changes, the proposed modifications set forth in the request for review. The decision different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for system enhancement initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iv) limits the tax savings that must be returned to customers to those savings generated by disallowed operating expenditures. The decision different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. The CPUC approved the decision different on May 7, 2020.

As it relates to the additional $198 million in disallowed costs as adopted in the decision different, the Utility has recorded the full amount, primarily in the WMPMA through December 31, 2021.

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 currently being held in abeyance until the FERC addresses the ROE issue.

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 2021 by approximately $324 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 has recorded approximately $197 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.

2018 CEMA Interim Rate Relief Subject to Refund

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented commencing on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund.

On November 2, 2021, the Utility filed a settlement agreement with the active parties in the matter. The settlement agreement, if approved by the CPUC, would authorize the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount has already been collected in interim rates. The interim rates would become final and no longer subject to refund. The remainder of the authorized revenue requirement that has yet to be collected would be amortized over a 12-month period.

2020 WMCE Interim Rate Relief Subject to Refund

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities (the “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California wildfires and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

As previously disclosed, on October 23, 2020, the CPUC approved $447 million in interim rate relief (which includes interest) pertaining to costs addressed in the 2020 WMCE application. All of the costs presented in the 2020 WMCE application are subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.

The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and are incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflect work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

On September 21, 2021, the Utility filed a motion with the CPUC seeking approval of a settlement agreement that would authorize the Utility to continue to recover an interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On September 23, 2021, the CPUC extended the statutory deadline for a PD in this hearing to April 1, 2022.

2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit

In its final decision in the Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount forecast to be recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The audit report was released June 2, 2020 and did not recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit.

On July 31, 2020, the Utility filed an application seeking recovery of $416.3 million in 2015 to 2022 revenue associated with $512 million of recorded capital expenditures. On July 7, 2021, the Utility filed a joint motion to adopt a settlement agreement reached with the active parties in the proceeding. If approved by the CPUC, the settlement agreement would resolve all issues in this proceeding and would authorize a $356.3 million revenue requirement for the period of 2015 through 2022. Of this amount, $313.3 million of revenues for the period 2015 through 2021 would be amortized in rates over 60 months and $43 million associated with 2022 would be amortized in rates over 12 months through an annual gas true-up filing for rates effective January 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application would be included in test year 2023 rate base in the Utility’s consolidated 2023 GRC. No party submitted comments on the settlement.

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

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 (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $77 million and $144 million as of December 31, 2021 and December 31, 2020, 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 January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. On March 30, 2020, the Bankruptcy Court granted the Utility’s motion to dismiss this class action 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. The appellant filed its opening brief on June 25, 2021. A former executive director of the CPUC filed an amicus brief on July 2, 2021, asking the Ninth Circuit Court of Appeals to reverse the decision of the District Court and to remand the case for further proceedings. The answering brief of PG&E Corporation and the Utility was filed August 25, 2021. On September 1, 2021, the CPUC filed an amicus brief asking the Ninth Circuit Court of Appeals to affirm the District Court’s dismissal. The appellant’s reply brief was filed on October 15, 2021. A panel of the Ninth Circuit Court of Appeals heard oral argument on the plaintiff’s appeal on January 12, 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.

Based on the information currently 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 a charge during the fourth quarter ended December 31, 2021 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. Violations can result in penalties, remediation and other relief.

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, 2021		December 31, 2020
Topock natural gas compressor station	$	299	$	303
Hinkley natural gas compressor station	123		132
Former MGP sites owned by the Utility or third parties (1)	667		659
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	104		111
Fossil fuel-fired generation facilities and sites (3)	70		96
Total environmental remediation liability	$	1,263	$	1,301

(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 hazardous waste laws. The Utility has a comprehensive program in place designed 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, 2021, 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, 2021, the Utility expected to recover $982 million 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 California 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 will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $220 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 HSM, 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 currently 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 2022. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 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 $477 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, 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 $50 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 HSM, 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 $43 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the 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 $2.7 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 also 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 this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured 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.

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $42 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $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 $13.6 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.6 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.

Diablo Canyon Outages

Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator occurred during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. During July 2020 through April 2021, the Utility implemented effective corrective actions. The Utility continues to monitor the affected component.

If additional shutdowns occur in the future, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC in the 2021 Energy Resource Recovery Account compliance proceeding.

PG&E Corporation and the Utility do not currently believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

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, 2021:


	Power Purchase Agreements
(in millions)	Renewable Energy		Conventional Energy		Other		Natural Gas		Nuclear Fuel		Total
2022	$	2,062	$	530	$	61	$	823	$	42	$	3,518
2023	2,043		425		61		191		41		2,761
2024	2,020		282		61		157		27		2,547
2025	2,009		216		61		157		—		2,443
2026	1,948		204		21		140		—		2,313
Thereafter	19,310		539		19		52		—		19,920
Total purchase commitments	$	29,392	$	2,196	$	284	$	1,520	$	110	$	33,502

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. As of December 31, 2021, renewable energy contracts expire at various dates between 2022 and 2041.

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 2022 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, 2021, QF contracts in operation expire at various dates between 2022 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 amounted to $3.0 billion in 2021, $2.9 billion in 2020, and $3.0 billion in 2019.

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 US 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 2022 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, amounted to $1.2 billion in 2021, $0.8 billion in 2020, and $0.9 billion in 2019.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2022 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 amounted to $79 million in 2021, $111 million in 2020, and $74 million in 2019.

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 2022 and 2052. At December 31, 2021, the future minimum payments related to these commitments were as follows:


(in millions)	Other Commitments
2022	$	43
2023	65
2024	81
2025	77
2026	74
Thereafter	2,938
Total minimum lease payments	$	3,278

Payments for other commitments amounted to $50 million in 2021, $45 million in 2020, and $48 million in 2019. 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.

Oakland Headquarters Lease

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 will begin on or about 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”). The Purchase Price would not be paid until 2023.

As space in the Lakeside Building becomes available following the expiration of existing tenants’ leases and completion of the redevelopment of the property to the Utility’s specifications, the Utility expects to relocate employees and operations from the SFGO and certain East Bay office locations to the Lakeside Building in phases over several years, beginning in 2022.

At December 31, 2021, the Lease had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

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, 2021, 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, 2021.

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, 2021, 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, 2021 and 2020, the related consolidated statements of income, comprehensive income, equity and cash flows, for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 10, 2022, 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 US 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 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 14 to the financial statements

Critical Audit Matter Description

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

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a high degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset 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 the costs approved by a CPUC decision for tracking purposes that meet the definition of a regulatory asset 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 decision for tracking purposes meet the definition of a regulatory asset 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 for Pacific Gas and Electric Company 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 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 Pacific Gas and Electric Company’s filings with the CPUC and the filings with the CPUC by intervenors that may affected Pacific Gas and Electric Company’s future rates, for any evidence that might contradict management’s assertions.
For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.
We evaluated whether the Company’s disclosures 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—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Company has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire and 2021 Dixie fire. The Company has recorded an estimated probable loss of $2,325 million as of December 31, 2021, which represents the lower end of the range of reasonably possible losses in connection with the fires.

We identified wildfire-related contingencies and the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses and (2) the outcome of the wildfire-related contingencies materially affects the Company’s financial position, results of operations, and cash flows. This required the application of a high degree of auditor judgment and extensive audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses and disclosure related to wildfire-related contingencies.

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 and related disclosures included the following, among others:

We tested the effectiveness of controls over (1) the Company’s determination of whether a loss was probable or reasonably possible; (2) the determination of the significant assumptions, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may affect 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 or reasonably possible for the wildfires by inquiring of management and the Company’s legal counsel regarding the amounts of probable and reasonably possible losses, including the potential impact of information gained through investigations into the cause of the fires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.
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.

Sale of Transmission Tower Wireless Licenses Agreement—Refer to Notes 3 and 4 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company, granted an exclusive license to a third party to sublicense and market wireless communications equipment attachment locations on the Utility’s structures and to add additional cell sites to the license. The Utility received $947 million in proceeds, and recorded $370 million as a financing obligation, $106 million as a contract liability (deferred revenue), and $471 million as regulatory liabilities.

We identified the accounting for the sale of the wireless licenses as a critical audit matter due to the significant judgments made by management in the application of accounting guidance. This required specialized knowledge of accounting for the sale of future revenue and leases as well as rate regulation due to its inherent complexities and extensive 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 Sale of Transmission Tower Wireless Licenses Agreement included the following:

We tested the effectiveness of controls over the evaluation of the accounting treatment for the Sale of Transmission Tower Wireless Licenses Agreement.
With the assistance of professionals in our firm having expertise in accounting for the sale of future revenue and leases, we evaluated the conclusions regarding the sale of future revenue, deferred revenue and regulatory liability accounting treatment applied to the Sale of Transmission Tower Wireless Licenses Agreement by performing the following:

◦Reading the contract terms and conditions included in the agreements

◦We read the Company’s analysis of the appropriate accounting guidance

◦Evaluating the conclusions regarding the accounting guidance used to account for the transaction

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

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 10, 2022, 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 US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Critical Audit Matters

Regulation and Regulated Operations – Refer to Notes 3, 4 and 14 to the financial statements

Critical Audit Matter Description

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utilities Commission (“CPUC”) or the Federal Energy Regulatory Commission 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 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. 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 affected account balances and disclosures and the high degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a high degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset under GAAP and are recorded at the appropriate amount.

How the Critical Audit Matter Was Addressed in the Audit

We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery 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 decision for tracking purposes meet the definition of a regulatory asset 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 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 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 the filings with the CPUC by intervenors that may affect the Utility’s future rates, for any evidence that might contradict management’s assertions.
For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.
We evaluated whether the Utility’s disclosures 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—Refer to Note 14 to the financial statements

Critical Audit Matter Description

The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire and 2021 Dixie fire. The Utility has recorded an estimated probable loss of $2,325 million as of December 31, 2021, which represents the lower end of the range of reasonably possible losses in connection with the fires.

We identified wildfire-related contingencies and the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses and (2) the outcome of the wildfire-related contingencies materially affects the Utility’s financial position, results of operations, and cash flows. This required the application of a high degree of auditor judgment and extensive audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses and disclosure related to wildfire-related contingencies.

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 and related disclosures included the following, among others:

We tested the effectiveness of controls over (1) the Utility’s determination of whether a loss was probable or reasonably possible; (2) the determination of the significant assumptions, including the information gained through investigations into the cause of the fires, information from claimants, and the advice of legal counsel that may affect 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 or reasonably possible for the wildfires by inquiring of management and the Utility’s legal counsel regarding the amounts of probable and reasonably possible losses, including the potential impact of information gained through investigations into the cause of the fire, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.
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 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.

Sale of Transmission Tower Wireless Licenses Agreement—Refer to Notes 3 and 4 to the financial statements

Critical Audit Matter Description

The Utility has granted an exclusive license to a third party to sublicense and market wireless communications equipment attachment locations on the Utility’s structures and add additional cell sites to the license. The Utility received $947 million in proceeds, and recorded $370 million as a financing obligation, $106 million as a contract liability (deferred revenue), and $471 million as regulatory liabilities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of accounting guidance for the Sale of Transmission Tower Wireless Licenses Agreement included the following:

We tested the effectiveness of controls over the evaluation of the accounting treatment for the Sale of Transmission Tower Wireless Licenses Agreement.
With the assistance of professionals in our firm having expertise in accounting for the sale of future revenue and leases, we evaluated the conclusions regarding the sale of future revenue, deferred revenue and regulatory liability accounting treatment applied to the Sale of Transmission Tower Wireless Licenses Agreement by performing the following:

◦Reading the contract terms and conditions included in the agreements

◦Evaluating the conclusions regarding the accounting guidance used to account for the transaction

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

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

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, 2021, 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, 2021, 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, 2021, of the Company and our report dated February 10, 2022, 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 10, 2022

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, 2021, 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, 2021, 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, 2021, of the Utility and our report dated February 10, 2022, expressed an unqualified opinion on those financial statements.

Basis for Opinion

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

Definition and Limitations of Internal Control over Financial Reporting

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

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 10, 2022

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