~~DIP Credit Agreement~~

~~In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, which received final approval from the Bankruptcy Court on March 27, 2019.~~

~~On July 1, 2020, the DIP Facilities (as defined in the DIP Credit Agreement) were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.~~Financial Resources

Equity Financings

On ~~July 23, 2020,~~April 30, 2021, PG&E Corporation ~~sent a notice of termination to the managers of the Amended and Restated~~entered into an Equity Distribution Agreement ~~dated as of February 17, 2017, effectively terminating~~with the ~~agreement on that date. As of~~Agents, the ~~termination date for this agreement, there were no issuances under this agreement.~~

In connection with its emergence from Chapter 11, in July 2020, PG&E Corporation issued for gross proceeds of approximately $9.0 billion (i) 423.4 million shares of its common stock (the “Common Stock Offering”), (ii) 342.1 million shares of common stock to the PIPE Investors pursuant to the Investment Agreement, (iii) prepaid forward contracts between PG&E CorporationForward Sellers and the ~~Backstop Parties dated~~Forward Purchasers (each as ~~of June 19, 2020 (the “Forward Stock Purchase Agreements”) and (iv) 14.5 million of its equity units (the “Equity Units” and such offering~~defined in “At the ~~“Equity Unit Offering”).~~

~~In August 2020, PG&E Corporation issued (i) 1.45 million~~Market Equity Units to the Equity Units Underwriters upon their exercise of their over-allotment option to purchase up to 1.45 million additional Equity Units (such issuance, the “Additional Units Issuance”) and (ii) 42.3 million shares to the Backstop Parties pursuant to the Forward Stock Purchase Agreements (with the balance of the Forward Stock Purchase Agreements being redeemed with the cash proceeds of these additional Equity Units).

The prepaid forward stock purchase contract portion of the Equity Units issued in July and August 2020 represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value 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 purchase contracts and subject to certain adjustments as provided therein. The settlement date of the purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. Such gross proceeds were used to fund distributions under the Plan.

For the year ended December 31, 2020, PG&E Corporation made equity contributions to the Utility of $12.9 billion in cash and 478 million shares of PG&E Corporation common stock. Such shares were transferred to the Fire Victim Trust.

~~Debt Financings~~

~~Utility~~

On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and between the Escrow Agent and the Utility. On July 1, 2020, the net proceeds from the sale of the Mortgage Bonds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan.

On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (collectively, the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt.

On the Effective Date, pursuant to the Plan, the Utility reinstated approximately $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility’s delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes.

The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first priority lien, subject to permitted liens, on substantially all of the Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other existing or future first mortgage bonds issued under the Utility’s mortgage indenture.

On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated.

On November 16, 2020, the Utility completed the sale of $1.45 billion aggregate principal amount of floating rate first mortgage bonds due November 15, 2021. Proceeds from the sale of the mortgage bonds were used for general corporate purposes, including the repayment of borrowings outstanding under the Receivables Securitization Program and under the Utility Revolving Credit Agreement.

~~For more information, see “Other Short-term Borrowings” and “Long-term Debt”~~Distribution Program” in Note 57 of the Notes to the Consolidated Financial Statements in Item 8.8), 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. 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 (as defined in “At the Market Equity Distribution Program” in Note 7 of the Notes to the Consolidated Financial Statements in Item 8) with the Forward Purchasers. On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date for this program, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement.

PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term debt, short-term debt, and the potential sale of a minority interest in Pacific Generation. (See “Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets” below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “PG&E Corporation Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”). The PG&E Corporation Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The proceeds of the PG&E Corporation Term Loan were initially deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the PG&E Corporation Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.

In accordance with the Term Loan Credit Agreement, PG&E Corporation is required to repay the principal amount outstanding on the PG&E Corporation Term Loan in an amount equal to $6.875 million on the last business day of each quarter.Debt Financings

On February ~~1, 2021, PG&E Corporation entered into a repricing amendment with~~18, 2022, the ~~lenders under the Term Loan Credit Agreement pursuant to which, among other things, the applicable interest rate was reduced.~~

~~Additionally, on June 23, 2020, PG&E Corporation~~Utility completed the sale of (i) $1 billion aggregate principal amount of ~~5.00% Senior Secured Notes~~3.25% First Mortgage Bonds due ~~July 1, 2028~~2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in an amount equal to $1.0 billion, and for general corporate purposes.

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

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $1$750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of a portion of the loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

SB 901 Securitization

On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of ~~5.25% Senior Secured Notes due July 1, 2030 (collectively, the “Notes”~~senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). The Series 2022-A Recovery Bonds were issued in five tranches:


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

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the ~~Notes were initially deposited into an account at~~Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The ~~Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by~~Utility used the ~~Escrow Agent as collateral pursuant to an escrow agreement by and amount the Escrow Agent and PG&E Corporation. On July 1, 2020, the net~~remaining proceeds from the ~~sale~~issuance of the ~~Notes were released from escrow and, together with~~Series 2022-A Recovery Bonds for the ~~net proceeds from certain other Plan financing transactions, were used~~repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to ~~effectuate the reorganization of PG&E Corporation and~~ the Utility ~~in accordance with the terms and conditions contained in the Plan.~~Revolving Credit Agreement.

On ~~the Effective Date,~~July 20, 2022, PG&E ~~Corporation repaid and terminated $350~~Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). The Series 2022-B Recovery Bonds were issued in five tranches:


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

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of ~~borrowings, plus interest, fees and other expenses arising~~loans outstanding under ~~or in connection with~~ the 2022A Utility Term Loan Credit Agreement ~~dated~~ as defined below, and (3) the repayment of ~~April 16, 2018, among~~a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024.

AB 1054 Securitization

On November 30, 2022, PG&E ~~Corporation, as borrower,~~Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The net proceeds were used by the ~~several lenders party thereto and Mizuho Bank Ltd., as administrative agent.~~Utility to fund fire risk mitigation capital expenditures that were incurred by the Utility from the period beginning October 2021 through October 2022.

For more information, see ~~“Long-Term Debt”~~“AB 1054” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

Credit Facilities

As of December 31, 2022, PG&E Corporation and the Utility had $500 million and $1.5 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the periods set forth in the amendment. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time.

Utility

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

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

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

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

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM., and Citibank, N.A. as co-administrative agents and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement has tenor of three years, subject to two one-year extension options. The proceeds from the borrowings under the Utility Revolving Credit Agreement, ~~were used~~which it subsequently amended. On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, ~~fund, in part, transactions contemplated under~~among other things, (i) increase the ~~Plan~~aggregate commitments provided by the lenders to $4.4 billion and ~~are intended~~(ii) extend the maturity date of such agreement to ~~finance working capital needs, capital expenditures and other general corporate purposes~~June 22, 2027 (subject to a one-year extension at the option of the ~~Utility and its subsidiaries.~~Utility).

~~In addition, on~~PG&E Corporation

On July 1, 2020, PG&E Corporation entered into the Utility obtained a $3 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Agreement”) with JPM, as administrative agent, and the other lenders from time to time party thereto. The facilities under the Utility Term LoanCorporation Revolving Credit Agreement, consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date forwhich it subsequently amended. On October 4, 2022, PG&E Corporation further amended the ~~Utility 364-Day Term Loan Facility is June 30, 2021 and~~Corporation Revolving Credit Agreement to, among other things, extend the maturity date ~~for~~of such agreement to June 22, 2025 (subject to a one-year extension at the ~~Utility 18-Month Term Loan Facility is January 1, 2022. The proceeds from the loans under the Utility Term Loan Credit Agreement were used to fund, in part, transactions contemplated under the Plan.~~

~~At December 31, 2020, the Utility had $3.0 billion~~option of ~~debt outstanding under the Term Loan Credit Agreement and had $1.9 billion available under the $3.5 billion Utility Revolving Credit Agreement.~~PG&E Corporation).

For more information, see “Credit Facilities” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

~~PG&E Corporation~~Intercompany Note Payable

On ~~July 1, 2020,~~August 11, 2021, PG&E Corporation ~~entered into a $500~~borrowed $145 million revolving credit agreement (the “Corporation Revolving Credit Agreement”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Agreement has a maturity date three years after its Effective Date, subject to two one-year extensions at the option of PG&E Corporation. The proceeds from loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

On the Effective Date, PG&E Corporation repaid and terminated $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent.

~~At December 31, 2020, PG&E Corporation did not have any borrowings outstanding under the Corporation Revolving Credit Agreement.~~

~~For more information, see “Credit Facilities” in Note 5 to the Consolidated Financial Statements in Item 8.~~

~~Receivables Securitization Program~~

On October 5, 2020, the Utility, in its individual capacity and in its capacity as initial servicer, 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. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The Utility has pledged to the Lenders 100% of the equity interests in the SPV as security for the repayment of the loans. The aggregate principal amount of the loans made by the Lenders cannot exceed $1 billion outstanding at any time.

The loans under the Receivables Securitization Program bear interest based on a spread over LIBOR dependent on the tranche period thereto and any breakage fees accrued. The receivables financing agreement contains customary LIBOR benchmark replacement language giving the administrative agent, with consent from the SPV as to the successor rate, the right to determine such successor rate. The Receivables Securitization Program contains certain customary representations and warranties and affirmative and negative covenants, including as to the eligibility of the receivables being sold by the Utility and securing the loans made by the Lenders, as well as customary reserve requirements, Receivables Securitization Program termination events, and servicer defaults. The Receivables Securitization Program termination events permit the Lenders to terminate the agreement upon the occurrence of certain specified events, including failure by the SPV to pay amounts when due, certain defaults on indebtedness under the Utility’s credit facility, certain judgments, a change of control, certain events negatively affecting the overall credit quality of transferred receivables and bankruptcy and insolvency events.

The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated, at which time no further advances will be available and the obligations thereunder must be repaid in full no later than (i) the date that is 180 days following such date or (ii) such earlier date on which the loans under the program become due and payable.

~~In general, the proceeds from the sale of the accounts receivable are used by the SPV to pay the purchase price for accounts receivables it acquires~~ from the Utility and may be used to fund capital expenditures, repay borrowings on the Utility Revolving Credit Facility, satisfy maturing debt obligations, as well as fund working capital needs and other approved uses.under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

Although the SPV is a wholly owned consolidated subsidiary of the Utility, the SPV is legally separate from the Utility. The assets of the SPV (including the accounts receivable) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program is accounted for as a secured financing. The pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets.

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 ~~April 3, 2019,~~February 8, 2022, the ~~court overseeing the Utility’s probation issued an order imposing new conditions~~Board of ~~probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s WMP.~~

~~On March 20, 2020, PG&E Corporation and~~Directors of the Utility ~~filed a Case Resolution Contingency Process Motion with~~authorized 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”payment 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~~and unpaid dividends on the Utility’s preferred stock ~~have been paid. Additionally,~~as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022. In addition to the ~~CPUC requires~~dividends paid in arrears, the Utility ~~to maintain a capital structure composed~~paid approximately $11 million of ~~at least 52% equity~~dividends on ~~average.~~redeemable preferred stock during the year ended December 31, 2022. On ~~May 28, 2020,~~December 15, 2022, the ~~CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants~~Board of Directors of the Utility ~~a temporary, five-year waiver from compliance with~~declared dividends on its ~~authorized capital structure for~~outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023.

On June 15, 2022, the ~~financing in place upon~~Board of Directors of the Utility also reinstated the dividend on the Utility’s ~~emergence from Chapter 11.~~common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. On December 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on December 20, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

Subject to the ~~foregoing~~dividend restrictions described in Note 7 of the Notes to the Consolidated Financial Statements in Item 8, any decision to declare and pay dividends on PG&E Corporation’s common stock in the future will be made at the discretion of the ~~Boards~~Board of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions of PG&E Corporation, and other factors that the ~~Boards~~Board of Directors of PG&E Corporation may deem relevant. ~~As of December 31, 2020, it is uncertain as~~Pursuant to ~~when~~the Confirmation Order, PG&E Corporation ~~and the Utility will commence the payment of~~may not pay dividends on ~~their~~shares of its common stock ~~and~~until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when ~~the Utility~~it will commence the payment of dividends on its ~~preferred~~common stock.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for 2022 and 2021.

See “Liquidity and Financial Resources” in Item 7 of the 2021 Form 10-K for discussion of the Utility’s cash flows for 2021 compared to 2020.

The Utility’s cash flows were as follows:

Year Ended December 31,
(in millions) 2020 2019 2018
Net cash provided by (used in) operating activities $ (19,047) $ 4,810 $ 4,704
Net cash used in investing activities (7,748) (6,378) (6,564)
Net cash provided by financing activities 26,070 1,395 2,708
Net change in cash, cash equivalents, and restricted cash $ (725) $ (173) $ 848


	Year Ended December 31,
(in millions)	2022		2021
Net cash provided by (used in) operating activities	$	3,831	$	2,448
Net cash used in investing activities	(10,069)		(7,050)
Net cash provided by financing activities	6,879		4,379
Net change in cash, cash equivalents, and restricted cash	$	641	$	(223)

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During 2020, net cash provided by operating activities decreased by $23.9 billion compared to 2019. This decrease was primarily due to the payment of $18.8 billion in satisfaction of pre-petition wildfire-related claims (including claims associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire), and the initial, first and second annual contributions made to the Wildfire Fund of $5.2 billion, with no similar payments made in 2019.

~~During 2019,~~2022, net cash provided by operating activities increased by ~~$106 million~~$1.4 billion compared to ~~2018.~~the same period in 2021. This increase was partially due to an increase in base revenues authorized in the 2020 GRC and additional revenues as authorized through the FERC formula rate and a decrease in ~~interest paid from $773 million to $7 million~~operating and maintenance expense as a result of operating cost efficiencies. In addition, during 2022, the ~~automatic stay~~Utility made a payment to the Fire Victim Trust of $592 million as compared to a payment of ~~the Petition Date. Additionally, income taxes paid decreased from $59~~$758 million in ~~2018 to zero~~the same period in 2019. These decreases in amounts paid were offset by an increase in amounts paid for reorganization items, and enhanced and accelerated inspections and repairs of transmission and distribution assets in 2019, with no similar payments in 2018, partially offset by additional amounts not paid due to the automatic stay as of the Petition Date.2021.

Future cash flow from operating activities will be affected by various factors, including:

•the timing and amount of costs in connection with the 2019 Kincade ~~fire;~~

•fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of ~~costs in connection with the 2020 Zogg fire;~~any potential related insurance, Wildfire Fund, and regulatory recoveries;

•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see ~~“Enforcement Matters”~~“Wildfire-Related Securities Class Action” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below for more information);

•the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service ~~territory,~~area, the ability of the Utility to collect on its customer ~~invoices,~~receivables, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover ~~from customers~~through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing;

•the timing and amounts of ~~annual contributions to the Wildfire Fund and if necessary, the availability of~~available funds to pay eligible claims for liabilities arising from future wildfires;

•the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 ~~and 2020-2022 WMPs~~WMP that are not currently being recovered inthrough rates (see “Regulatory Matters” below for more information);

•the timing and ~~amount~~amounts of ~~premium payments related to wildfire insurance~~available funds collected for self-insurance (see ~~“Insurance Coverage”~~“2023 General Rate Case” in ~~Note 14~~the Regulatory Matters section of ~~the Notes to the Consolidated Financial Statements in~~ Item 87. Management’s Discussion and Analysis for more information);

•the timing ~~of and amount~~ of the gain to be returned to customers from the sale of the ~~SFGO;~~SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and

•the timing and outcomes of the ~~FERC TO18~~Utility’s pending and ~~TO19 rate cases, 2018 and 2019 CEMA applications, WEMA application, WMCE application,~~ future ~~applications for cost recovery of amounts recorded to the FRMMA, CPPMA, WMPMA, VMBA, WMBA and RTBA, future cost of capital proceedings and other~~ ratemaking and regulatory ~~proceedings.~~

~~Investing Activities~~

~~Net cash used in investing activities increased by $1.4 billion during 2020 as compared~~proceedings, including the extent to 2019 partially due to the payment of pre-petition vendor payables for capital expenditures as a result of emerging from Chapter 11. Net cash used in investing activities decreased by $186 million during 2019 as compared to 2018 primarily due to a decrease in cash paid for capital expenditures as a result of the automatic stay as of the Petition Date. The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur between $7.5 billion and $8.3 billion in capital expenditures in 2021. Additionally, future cash flows from investing activities will be impacted by the timing of and amount received from the proposed sale of the Utility’s SFGO.

~~Financing Activities~~

During 2020, net cash provided by financing activities increased by $24.7 billion as compared to 2019. This increase was primarily due to PG&E Corporation making a cash equity contribution to the Utility of approximately $13.0 billion, and due to the Utility receiving $10.4 billion in proceeds from the issuance of short-term and long-term first mortgage bonds, with no similar activity in 2019. Additionally, the Utility had net borrowings of $4.6 billion under its credit facilities during the year ended December 31, 2020, with no similar activity in 2019 due to the Utility entering into the facilities in 2020. These increases were partially offset by net repayments of $1.5 billion on the DIP facilities in 2020, as compared to net borrowings of $1.5 billion on the DIP facilities in 2019.

During 2019, net cash provided by financing activities decreased by $1.3 billion as compared to 2018. This decrease was primarily due to $2.9 billion of net borrowings under revolving credit facilities in 2018, partially offset by $1.5 billion of net borrowings under the DIP initial term loan facility in 2019.

~~CONTRACTUAL COMMITMENTS~~

~~The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2020:~~

Payment due by period
(in millions)
Less Than
1 Year
1-3
Years 3-5
Years More Than
5 Years Total
Utility
Long-term debt (1)
$ 4,043 $ 7,778 $ 4,209 $ 35,895 $ 51,925
Purchase obligations (2)
Power purchase agreements 2,917 4,896 4,198 21,657 33,668
Natural gas supply, transportation, and storage 466 349 302 184 1,301
Nuclear fuel agreements 64 103 47 — 214
Pension and other benefits (3)
342 684 684 342 2,052
Operating leases (2)
42 80 129 3,019 3,270
Preferred dividends (4)
14 28 28 — 70
PG&E Corporation
Long-term debt (1)
— — 2,901 2,000 4,901
Total Contractual Commitments $ 7,888 $ 13,918 $ 12,498 $ 63,097 $ 97,401

~~(1)~~ Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2020 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. (See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.)

~~(2)~~ ~~See “Purchase Commitments” and “Other Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~(3)~~ See Note 12 of the Notes to the Consolidated Financial Statements in Item 8. Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the amount shown in the column entitled “more than 5 years” represents only 1 year of contributions for the Utility’s pension and other benefit plans.

~~(4)~~ Beginning with the three-month period ending January 31, 2018, quarterly cash dividends on the Utility’s preferred stock were suspended. While the timing of cumulative dividend payments is uncertain, it is assumed for the table above to be payable within a fixed period of five years based on historical performance. (See Note 7 of the Notes to the Consolidated Financial Statements in Item 8.)

~~The contractual commitments table above excludes potential payments associated with unrecognized tax positions. Due to the uncertainty surrounding tax audits,~~ PG&E Corporation and the Utility ~~cannot make reliable estimates of the amounts and periods of future payments~~are able to ~~major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject to examination are discussed~~recover their costs through regulated rates as recorded in ~~Note 9 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Except~~memorandum accounts or balancing accounts, or as otherwise set forth in the Plan and the Confirmation Order, all executory contracts and unexpired leases were assumed by PG&E Corporation or the Utility, as applicable, on the Effective Date. Accordingly, any description of an executory contract or unexpired lease with PG&E Corporation or the Utility in this Annual Report on Form 10-K, including where applicable a quantification of the obligations under any such executory contract or unexpired lease, is qualified by any overriding assumption or rejection rights PG&E Corporation or the Utility, as applicable, has under the Bankruptcy Code, the Plan, and the Confirmation Order. Further, nothing herein is or shall be deemed to be an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and PG&E Corporation and the Utility expressly reserve all of their rights with respect thereto.

requested.

~~Off-Balance Sheet Arrangements~~

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 1516 of the Notes to the Consolidated Financial Statements in Item 8.

Investing Activities

~~ENFORCEMENT AND~~

Net cash used in investing activities increased by $3.0 billion during 2022 as compared to the same period in 2021. This increase was primarily driven by a $1.9 billion increase in capital expenditures, including additional system hardening and emergency response work performed in 2022. Additionally, the Utility purchased $1.0 billion of investments as part of the creation of the customer credit trust, with no similar purchases in 2021.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the SB 901 securitization is designed to be rate neutral to customers.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur between $7.9 billion and $11.2 billion in 2023. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building, and the timing and amount of contributions to the customer credit trust, including shareholder tax benefits, and $1.0 billion of cash to be contributed in 2024.

Financing Activities

Net cash provided by financing activities increased by $2.5 billion during 2022 as compared to the same period in 2021. The increase was primarily due to the issuance of $7.5 billion of SB 901 recovery bonds and a decrease of $850 million in net repayments of short-term debt. These increases were partially offset by a $5.9 billion increase in amounts paid to satisfy long-term debt outstanding in 2022 compared to the same period in 2021.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in ~~Notes 14~~Note 2, Note 15, and 1516 of the Notes to the Consolidated Financial Statements in Item 8.8 that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

~~U.S. District Court Matters~~

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and ~~Probation~~other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

During the year ended December 31, 2022 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters.

•In February 2023, the CPUC approved a final decision, adopting without modification the Utility’s settlement agreement in its 2020 WMCE proceeding, pursuant to which the Utility will recover a revenue requirement of $1.04 billion. In January 2023, the Utility submitted a partial settlement regarding the 2021 WMCE application pursuant to which the Utility would receive a revenue requirement of $720.7 million. In December 2022, the Utility filed the 2022 WMCE application requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion.

•In December 2022, OEIS issued the Utility’s 2022 safety certification.

•In December 2022, the CPUC approved a resolution authorizing the Utility’s exit from the EOEP.

•In December 2022, the CPUC issued a final decision in the Utility’s 2023 cost of capital proceeding, which sets the Utility’s ROE for 2023 at 10%.

•In November 2022, OEIS issued its final decision approving the Utility’s 2022 WMP, which the CPUC ratified in December.

•In November 2022, the CPUC issued a final decision in the Utility’s 2022 cost of capital proceeding. The decision retains the Utility’s cost of capital previously authorized in the 2020 cost of capital proceeding.

•In September 2022, the Utility filed an application with the CPUC regarding the separation of its non-nuclear generation assets into a stand-alone Utility subsidiary and the potential sale of a minority interest in the newly-formed subsidiary to one or more investors to be identified.

•In September 2022, the Governor of California signed SB 884, which authorizes and expedites OEIS and CPUC review of a 10-year undergrounding plan.

•In September 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon until 2030. In October 2022, the Utility executed a loan agreement with the DWR for up to $1.4 billion. In November, the DOE conditionally selected the Utility to receive funding of up to $1.1 billion as part of the Civil Nuclear Credit Program.

•In August 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, and in November 2022, PG&E Recovery Funding LLC issued approximately $983 million aggregate principal amount of Series 2022-A Senior Secured Recovery Bonds. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

•In March 2022, the CPUC approved a settlement agreement for the Utility’s 2018 CEMA application approving a total revenue requirement of $683 million plus interest for its expenses and capital costs, which is approximately 90% of the Utility’s total cost recovery request.

•In February 2022, a CPUC decision finding $7.5 billion of stress test costs eligible for securitization pursuant to SB 901 and a financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds in May and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds in July. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

•In February 2022, the Utility served supplemental testimony for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines. In September 2022, the Utility submitted testimony updating the revenue requirement to reflect updates for escalation rates and federal tax law and guidance. As amended and updated, the Utility’s application requests revenue requirements of $15.82 billion and a weighted-average GRC rate base of $50.41 billion for its 2023 test year. In January 2023, the Utility filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding, for $183 million in expense and $127 million of capital expenditures. Also in January 2023, the CPUC approved a settlement pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize balancing accounts with limitations or caps to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2022, the Utility had recorded an aggregate amount of approximately $6.2 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Of these costs, approximately $856 million was authorized for recovery and accounted for as current, and $5.3 billion was accounted for as long term as of December 31, 2022. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8, “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications,” and “Catastrophic Event Memorandum Account Application” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table:

Proceeding

Request

Status

2020 WMCE

Revenue requirement of approximately $1.28 billion

Settlement agreement to recover $1.04 billion of revenue requirement approved February 2023.

2021 WMCE

Revenue requirement of approximately $1.47 billion

Partial settlement agreement to recover $721 million of revenue requirement filed January 2022. Settlement excludes VMBA’s $591 million revenue requirement.

2022 WMCE

Revenue requirement of approximately $1.36 billion

Filed December 15, 2022.

2018 CEMA

Revenue requirement of $763 million

Settlement agreement to recover $683 million plus interest approved March 2022.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2020 WMCE Application

On ~~August 9, 2016,~~September 30, 2020, the ~~jury~~Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the “2020 WMCE application”). The recorded expenditures, which excluded amounts disallowed as a result of the CPUC’s decision in the ~~federal criminal trial against~~OII into the ~~Utility~~multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the ~~United States District Court for~~area surrounding Yuba City (the “2017 Northern California wildfires”), and the ~~Northern District~~2018 Camp fire, consisted of ~~California,~~$1.18 billion in ~~San Francisco, found the Utility guilty on one count~~expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.approximately $1.28 billion.

The ~~probation includes a requirement that~~costs addressed in the ~~Utility not commit any local, state, or federal crimes~~2020 WMCE application cover activities mainly during the ~~probation period. As part of the probation, the Utility has retained the Monitor at~~years 2017 to 2019 and were incremental to those previously authorized in the Utility’s ~~expense.~~2017 GRC and other proceedings. The ~~goal~~majority of ~~the Monitor is~~costs addressed in this application reflected work necessary to ~~help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations,~~mitigate wildfire risk and to ~~maintain effective ethics, compliance~~respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue included amounts for the FHPMA of $293 million, the FRMMA and ~~safety related incentive programs on a Utility-wide basis.~~the WMPMA of $740 million, and the CEMA of $251 million.

On ~~August 7, 2020, after~~September 21, 2021, the Utility and certain parties filed a ~~number~~motion with the CPUC seeking approval of ~~filings involving different parties,~~a settlement agreement that would resolve all of the ~~court entered an order adopting the new conditions jointly proposed~~issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility ~~the Monitor, and the Department~~recover a revenue requirement of ~~Justice on June 24, 2020. Among other things, these conditions require~~$1.04 billion. The settlement agreement authorizes the Utility to ~~staff~~recover a revenue requirement of $591 million over a 24-month amortization period beginning March 2023, which is in addition to the interim rate relief of $447 million that was approved by an ~~in-house vegetation inspection manager and approximately 30 additional field inspectors to oversee vegetation management work. Further,~~earlier CPUC decision. On February 2, 2023, the CPUC approved a final decision adopting the settlement agreement without modifications.

2021 WMCE Application

On September 16, 2021, the Utility ~~is required~~filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to ~~implement~~wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings. The majority of the Utility’s proposed revenue requirement would be collected over a ~~program to assess the age and expected useful life of certain electrical components~~two-year period beginning in ~~high fire-threat areas, incorporate this information into its risk-based asset management programs, and provide monthly progress reports~~January 2023.

The Utility’s requested revenue requirement includes amounts recorded to the ~~Monitor.~~VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19.4 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery request of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction was a result of costs, such as employee business travel expenses and in-person training costs, that the Utility ~~must also hire additional inspectors~~was able to ~~oversee inspections~~avoid due to the pandemic.

On January 18, 2023, the Utility, TURN, and Cal Advocates filed a joint motion for approval of ~~its transmission assets and implement~~ a ~~90-day replacement~~settlement agreement, pursuant to which the Utility would receive a revenue requirement of $720.7 million. The settlement agreement does not address $591.9 million recorded to the VMBA, for ~~cold end hardware in high fire-threat areas with an observed material loss approaching 50%.~~which cost recovery will be determined separately by the CPUC.

2022 WMCE Application

On December ~~29,~~15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. The costs addressed in the 2022 WMCE application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings. In connection with the ~~court entered an order requiring~~2022 WMCE application, the Utility also requested interim rate relief of $1.1 billion to be recovered over 12 months beginning June 1, 2023. The remaining $224 million would be recovered after the CPUC issues a final decision.

The Utility has proposed a schedule that would call for a final decision by the CPUC in December 2023.

Catastrophic Event Memorandum Account Application

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. The Utility has historically sought such costs through standalone CEMA applications. More recently, the Utility has sought to recover CEMA-eligible costs through its WMCE applications.

In addition to the Utility’s responsibilities in responding to catastrophic events, in 2014, the CPUC directed the Utility to ~~show cause as~~perform additional fire prevention and vegetation management work in response to ~~why additional proposed conditions of probation should not be added. The proposed conditions would require~~the severe drought in California. Through 2019, the costs associated with this work were tracked in the CEMA. In the 2020 GRC decision, the CPUC required the Utility to ~~when determining which distribution lines to de-energize during a PSPS event: (i) take into account~~track these costs in the ~~extent to which vegetation bordering those lines is not in compliance with certain requirements, and (ii)~~VMBA for the period beginning January 1, 2020.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the ~~extent~~CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that ~~information shows~~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 ~~such vegetation presents a safety hazard in the event~~were exposed to years of ~~a windstorm, make a specific determination with respect to that distribution line~~drought conditions and ~~de-energize it unless the Utility finds in writing that there are specific reasons to believe that no safety issues exist.~~bark beetle infestation. The Utility filed ~~its response on January 20, 2021, proposing supplemental language~~three revisions to ~~clarify and specify how~~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.

On March 17, 2022, the CPUC approved a settlement agreement authorizing 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 had already been collected in interim rates. The interim rates became final and are no longer subject to refund. The remainder of the authorized revenue requirement will ~~implement~~be amortized over a 12-month period, which began on June 1, 2022.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the ~~new conditions proposed~~CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on approved revenue requirements and possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the ~~court. A hearing~~CPUC.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the matter was held on February 3, 2021. On February 4, 2021, the court entered an order indicating that, if certain alterations were made, the court may be willing to accept the Utility’s proposed modified conditions in lieuoutcomes of the conditions proposed in the court’s December 29, 2020 order. All parties and amici responded to the order on February 19, 2021 and any replies must be submitted by February 26, 2021. A hearing is scheduled for March 9, 2021.these applications.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table:

Rate Case

Request

Status

2023 GRC

Revenue requirement of $15.82 billion for 2023

A decision is scheduled for the third quarter of 2023.

2022 Cost of Capital

Leave cost of capital components at pre-2022 levels for 2022

Final decision issued November 2022, leaving the cost of capital components at pre-2022 levels for 2022. Intervenors filed application for rehearing in December 2022.

2023 Cost of Capital

Increase ROE to 11% and cost of debt to 4.31%

Final decision issued December 2022, adopting a 10% ROE. Intervenor filed application for rehearing in January 2023.

2015 GT&S

Revenue requirement of $416 million related to 2011-2014 capital expenditures subject to audit

Final decision issued July 2022 approving settlement to recover $356 million of revenue requirements.

2023 General Rate Case

On ~~February 4,~~June 30, 2021, the ~~court entered an order requiring~~Utility filed its 2023 GRC application with the CPUC (“the Original Application”). The 2023 GRC combined what had historically been separated into the GRC and GT&S rate cases. In a GRC, the CPUC approves annual revenue requirements for the first year (a “test year”) of the GRC period and typically authorizes the Utility to ~~show cause~~receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to ~~why~~collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the ~~additional~~Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the Original Application, the Utility proposed ~~conditions~~a series of ~~probation suggested by amici~~safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service.

Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony. On February 25, 2022 and February 28, 2022, the Utility served supplemental testimony for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility’s service area, the EPSS program, and its EVM program. On March 10, 2022, the Utility filed an amended application that revised and superseded the revenue requirement request in the Original Application. On September 6, 2022, the Utility submitted testimony updating the revenue requirement request in its 2023 GRC proceeding. The testimony reflected updates for escalation rates and federal tax law and guidance since the filing of the Original Application. On December 9, 2022, the Utility submitted a post-hearing reply brief. In the reply brief, the Utility updated the revenue requirement request due to the wildfire insurance settlement dated October 7, 2022 discussed below, stipulations with the parties regarding several disputed issues, and a reduction to the Utility’s forecast for wildfire system hardening mileage targets over the 2023 to 2026 rate case period.

As amended and updated, the Utility’s application requests revenue requirements of $15.82 billion and a weighted-average GRC rate base of $50.41 billion for its 2023 test year. The tables below compare the requested revenue requirements and rate base for the GRC period from 2023 through 2026 to those adopted for 2022 in the 2020 GRC and 2019 GT&S proceedings:


(in billions)	2022 (as adopted)		2023		2024		2025		2026
Requested revenue requirement	$	12.21	$	15.82	$	16.74	$	17.18	$	17.43
Requested weighted-average GRC rate base	39.21		50.41		55.39		59.56		63.68

Over the GRC period of 2023 through 2026, the Utility plans to make average annual capital investments of approximately $9.69 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

On July 22, 2022, the Utility submitted a request for the second track of this proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $206 million in expenses and $129 million in capital expenditures, resulting in a proposed revenue requirement of approximately $241 million, most of which is proposed to be collected over a two-year period beginning August 1, 2023. On January ~~27,~~6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023. The self-insurance will be funded through CPUC-jurisdictional rates at $400 million for test year 2023 and subsequent years until $1.0 billion of unimpaired self-insurance is reached. If losses are incurred, the settlement agreement contains an adjustment mechanism designed to adjust customer funded self-insurance based on the amount of wildfire related liabilities incurred in the previous year. For 2024, 2025, and 2026, if the estimated claims for wildfire events from the immediately preceding year exceed the amount collected for self-insurance in that same year, the self-insurance amount to be collected in rates during the following year would increase by 50% of the difference between the self-insurance amount collected and estimated claims for events in the immediately preceding year. As a result, the Utility could collect the self-insurance amounts over a longer period than it makes wildfire-related payments. The settlement agreement includes a five percent deductible, capped at a maximum of $50 million, on claims that are incurred each year. The settlement agreement prohibits the Utility from purchasing additional wildfire liability insurance from the commercial insurance market.

The Utility does not seek recovery of compensation of PG&E Corporation’s and the Utility’s officers within the scope of 17 Code of Federal Regulations 240.3b-7.

The CPUC’s schedule indicated a final decision on the first two tracks of this proceeding would be issued in the third quarter of 2023.

Cost of Capital Proceedings

2020 and 2022 Cost of Capital Applications

On December 19, 2019, the CPUC approved a final decision in the 2020 cost of capital application (the “2020 cost of capital application”), maintaining the Utility’s ROE at the 2019 level of 10.25% for the three-year period beginning January 1, 2020. The decision maintained the common equity component of the Utility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking) at 52% and reduced its preferred stock component from 1% to 0.5%. The decision also approved the cost of debt requested by the Utility.

On August 23, 2021, ~~filing~~the Utility filed an off-cycle 2022 cost of capital application with the CPUC. The Utility also concurrently filed a motion requesting that the revenue requirement for the 2022 cost of capital be recorded in memorandum accounts to be trued-up following a final decision in this proceeding. On October 28, 2021, the CPUC ruled that the Utility was required to comply with the cost of capital mechanism for 2022.

On November 3, 2022, the CPUC issued a final decision, finding that an extraordinary event occurred, and that the cost of capital adjustment mechanism should not be ~~added.~~implemented for 2022. The ~~proposed conditions would require~~final decision retains the cost of capital for 2022 previously authorized in the 2020 cost of capital proceeding, as adjusted, and closes this proceeding. On December 5, 2022, intervenors filed an application for rehearing. On December 20, 2022, the Utility ~~to: (i) hire~~filed a ~~chief data operations officer~~response to the application for rehearing.

For more information regarding this proceeding, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

2023 Cost of Capital Application

On April 20, 2022, the Utility filed an application with the ~~responsibility to review~~CPUC requesting that the CPUC authorize the Utility’s ~~information management~~cost of capital for its electric generation, electric distribution, natural gas distribution, and ~~record-keeping systems~~natural gas transmission and ~~manage~~storage rate base beginning on January 1, 2023 (the “2023 cost of capital application”).

In its 2023 cost of capital application, the ~~relationship to~~Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt.

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision.

The following table compares the currently authorized capital structure and rates of return with those adopted in the final decision for 2023, as corrected.


	2022 authorized by the 2022 Cost of Capital Application						2023 Cost of Capital decision
	Cost		Capital structure		Weighted cost		Cost		Capital structure		Weighted cost
Common equity	10.25	%	52.00	%	5.33	%	10.00	%	52.00	%	5.20	%
Preferred stock	5.52	%	0.50	%	0.03	%	5.52	%	0.50	%	0.03	%
Long-term debt	4.17	%	47.50	%	1.98	%	4.31	%	47.50	%	2.05	%
Weighted average cost of capital			100.00	%	7.34	%			100.00	%	7.28	%

For 2023, the Utility expects that the newly-adopted cost of capital will result in revenue requirement decreases of approximately $23 million for electric generation and distribution and $10 million for gas distribution operations, ~~including vegetation management work~~assuming 2022 authorized rate base amounts from the 2020 GRC decision. The revenues for the gas transmission and ~~PSPS; (ii) initiate steps to prevent data falsification or omission; (iii) propose a plan to mark trees in tier 2 and tier 3 high wildfire danger zones~~storage operations will decrease by approximately $7 million, assuming 2022 authorized rate base amounts from the 2019 GT&S decision. Actual revenue requirement changes resulting from the Utility’s requested ROE for ~~removal and track~~ the ~~status~~period beyond 2022 may differ from the amounts reflected above, pending the outcome of the ~~tree removal process~~2023 GRC.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for ~~vegetation management;~~interest on the Utility’s balancing and ~~(iv) propose steps~~memorandum accounts to ~~improve its information management and records-keeping process to improve information integrity, inform analysis, and inform and enhance daily operations including PSPS.~~reflect the Utility’s actual cost of short-term debt. The ~~Utility’s,~~Utility requested that the ~~Monitor’s,~~adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the ~~United States’ responses are due~~Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The Utility included an illustrative calculation using the period March 2021 to February 2022 with an adjustment to increase the rate by 153 basis points, which would result in an estimated $69 million increase in recovery of short-term financing costs associated with its recent balancing and memorandum account balances. The actual revenue requirement impact of the short-term debt proposal would differ depending on the final adjustment set each year and the recorded balances in the balancing and memorandum accounts. The decision deferred consideration of the proposal to a second phase of the proceeding.

The cost of capital that is approved in this proceeding is expected to be effective until December 31, 2025, unless the cost of capital adjustment mechanism is triggered. (For more information on the cost of capital adjustment mechanism, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8.)

On January 18, 2023, an intervenor filed an application for rehearing of the final decision. On February 2, 2023, the Utility filed a response to the application for rehearing.

2015 Gas Transmission and Storage Rate Case

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of 2011 to 2014 capital spending in excess of the amount adopted in the prior 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 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. On July 14, 2022, the CPUC approved a final decision approving the settlement agreement, which resolved all issues in this proceeding and authorized a $356 million revenue requirement for the period of 2015 through 2022. Of this amount, $313 million of revenues for the period 2015 through 2021 will be amortized in rates over 60 months and $43 million associated with 2022 will be amortized in rates over 12 months beginning August 1, 2022. Going forward, the as-yet undepreciated capital plant associated with this application was included in test year 2023 rate base in the Utility’s consolidated 2023 GRC.

Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

On January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50-basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Ninth Circuit Court of Appeals’ opinion.

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder.

On March ~~3, 2021,~~17, 2020, the FERC issued its order denying requests for rehearing that were previously filed by several parties. On May 11, 2020, the CPUC and ~~any reply by amici is due by March 10, 2021.~~a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals.

On ~~February 18, 2021,~~March 17, 2022, the ~~court~~Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation. The order would extinguish the Utility’s refund obligations that might have been required under the TO16 and TO17 rate cases had the Ninth Circuit Court of Appeals not found in the FERC’s favor. On May 2, 2022, the CPUC filed a petition for panel rehearing of the order. On May 25, 2022, the Ninth Circuit Court of Appeals issued a decision denying the request for rehearing and the request for a rehearing en banc.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

On July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network transmission rate base for 2017 was $6.7 billion. The Utility sought a ROE of 10.9%, which included an incentive component of 50-basis points for the Utility’s continuing participation in the CAISO.

On October 15, 2020, the FERC issued an order ~~requiring~~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 participants to the proceeding 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 ~~to show cause as to why an additional proposed condition of probation, which would require~~and intervenors. In 2021, the Utility filed four appeals. The appeals related to ~~“identify~~two issues: (1) impact of the Tax Act on TO18 rates in January and ~~remove any tree or~~February 2018 and (2) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through 2022 by approximately $416 million. A portion ~~thereof leaning toward any distribution line if it may contact~~of these common plant costs are expected to be recovered at the ~~line~~CPUC in a separate application and as a result, as of December 31, 2022, the Utility had recorded approximately $258 million to Regulatory assets.

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liability for the potential refund for TO18 by $30 million in 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding. On May 16, 2022 and May 31, 2022, the Utility filed a compliance filing and a refund report describing the adjustments made to the transmission revenue requirement, adjusted rates, and the calculation and mechanism of the refunds. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

Aside from the ~~side or fall~~ultimate outcome of the ROE rehearing request and the common plant allocation, the FERC’s orders in the TO18 proceeding are not expected to result in a material impact on the ~~line~~Utility’s financial condition, results of operations, liquidity, and ~~must do so~~ ~~regardless~~cash flows. Some of the ~~health~~issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases. The ROE rehearing request will not impact the TO20 rate case. See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 16 of the ~~tree[,]~~Notes to the Consolidated Financial Statements in Item 8.

Transmission Owner Rate Case for 2018 (the “TO19” rate case)

~~” should not be added. The Utility’s response is due by March 4, 2021, any response~~

On July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the ~~United States and/or amici is due~~Utility. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation and eliminating the refund obligation, and so the Utility was not obligated to make a refund to customers based on this matter. See “Transmission Owner Rate Cases for 2015 and 2016” above for a discussion of the incentive adder. As a result of the potential reduction to the TO18 revenue requirement, the Utility increased its regulatory liability for the potential refund for TO19 by $32 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding.

Transmission Owner Rate Case for 2019 (the “TO20” rate case)

On October 1, 2018, the Utility filed its TO20 rate case with the FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the effective date for rate changes. The FERC also ordered that the hearings be held in abeyance pending settlement discussions among the parties.

On March ~~11, 2021,~~31, 2020, the Utility filed a partial settlement with the FERC, which the FERC approved on August 17, 2020. On October 15, 2020, the Utility filed a settlement with the FERC resolving all of the remaining issues in the formula rate proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement established an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing by October 18, 2023 to be effective on January 1, 2024.

On December 30, 2020, the FERC approved the settlement without modification.

Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s ~~reply is due by March 17, 2021. A hearing~~TO20 rate case.

Under its formula rate, the Utility submits an annual update to the FERC each December for rates to go into effect on January 1 of the ~~matter is scheduled for March 23, 2021.~~following year. Parties have protested the Utility’s annual updates, and these protests are pending before the FERC.

Other Regulatory Proceedings

Enhanced Oversight and Enforcement Process

In the ~~course~~OII to Consider PG&E Corporation’s and the Utility’s Plan of ~~2020~~Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility’s operational performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and ~~2021,~~includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the ~~court entered numerous other orders, including~~WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics. The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in ~~connection~~coordination with the ~~Utility’s vegetation~~CPUC’s existing formal and informal reporting requirements and procedures. The EOEP does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and OIIs and to impose fines and penalties. The EOEP requires the Utility to report the occurrence of a triggering event to the CPUC’s executive director no later than five business days after the date on which any member of senior management of the ~~Utility’s PSPS program,~~Utility becomes aware of the ~~2018 Camp fire, the 2019 Kincade fire, and the 2020 Zogg fire.~~occurrence of a triggering event.

The Utility ~~expects~~is unable to ~~receive additional orders from the court in the future.~~predict whether fines or penalties may be imposed, or other regulatory actions may be taken.

Vegetation Management

The CPUC placed the Utility into step 1 of the EOEP on April 15, 2021 and imposed additional reporting requirements on the Utility. The CPUC’s resolution states that a step 1 triggering event had occurred because the Utility had “made insufficient progress toward approved safety or risk-driven investments related to its electric business.” The resolution found that, based on the CPUC’s evaluation of the Utility’s EVM work in 2020, the Utility was “not sufficiently prioritizing its Enhanced Vegetation Management (“EVM”) based on risk” and was “not making risk-driven investments.” The resolution also found that “less than five percent of the EVM work” the Utility completed in 2020 “was on the 20 highest risk power lines according to its own risk rankings.”

As required by the CPUC’s resolution, the Utility submitted a corrective action plan to the CPUC’s Executive Director on May 6, 2021, which was designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addressed the EVM situation that occurred in 2020 and provided a risk-informed EVM work plan for 2021. The Utility was required to update the information contained in the corrective action plan every 90 days, which it did.

On December 1, 2022, the CPUC issued a resolution authorizing the Utility’s exit from the EOEP.

Application for Post-Emergence SB 901 Securitization Transaction

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 recover $7.5 billion of 2017 wildfire claims costs through securitization that is designed to be rate neutral to customers through the creation of a corresponding customer credit trust, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a “securitization” refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds.

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. and approving a structure for the transaction. As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders, that will provide a monthly credit to customers that is anticipated to equal the securitized charges such that the securitization is designed to be rate neutral to customers. Subject to retention of the CPUC’s existing jurisdiction, the decision adopted a transaction structure comprised of four elements: (1) an initial shareholder contribution of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

In addition, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires, which the CPUC subsequently granted on May 11, 2021.

On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. The financing order authorized the issuance of bonds through the end of 2022. PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of Series 2022-A Recovery Bonds on May 10, 2022 and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds on July 20, 2022. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Application for Second AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. Pursuant to an earlier financing order issued by the CPUC authorizing the Utility’s initial application for AB 1054 securitization transaction, on November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

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

The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.  The application also requested that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC revenue requirements following the issuance of the recovery bonds. 

On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million then pending in the 2020 WMCE proceeding.

On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million aggregate principal amount of Series 2022-A Senior Secured Recovery Bonds.

2020-2022 Wildfire Mitigation Plan

The Utility’s 2022 WMP was submitted on February 25, 2022. The 2022 WMP addressed the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread, and reducing the impact of PSPS events. On November 10, 2022, OEIS approved the Utility’s 2022 WMP. On December 15, 2022, the CPUC ratified OEIS’s approval.

On December 5, 2022, OEIS issued its draft Annual Report on Compliance (“ARC”) for the Utility’s 2020 WMP. In the draft ARC, OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets but found that the Utility failed to meet targets highly correlated with risk, failed to achieve critical stated objectives, and failed to sufficiently address risk on its system. Consequently, OEIS found the Utility did not substantially comply with the WMP during the 2020 compliance period. The Utility submitted comments on the draft ARC in December 2022. If the OEIS final ARC report maintains the finding that the Utility failed to substantially comply with its 2020 WMP, the Utility may seek judicial review. If the ARC finds that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance. PG&E Corporation and the Utility cannot reasonably estimate at this time whether they will incur a loss in connection with the ARC or the amount of any such loss, as OEIS has not issued the final ARC and because any penalty issued by CPUC depends upon a number of factors.

Electric Integrated Resource Planning and Related Procurement

On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision required incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period from 2021 to 2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision required that at least 50% of LSEs resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directed the IOUs to act as the backstop procurement agent for CCAs and energy service providers that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision.

On June 30, 2021, the CPUC issued a mid-term reliability decision to address incremental electric system reliability needs between 2024 and 2026 due to, in part, the pending retirement of once-through-cooling natural gas plants in Southern California and the possible retirement of Diablo Canyon by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs. See “Extension of Diablo Canyon Operations” below. The decision set procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision set the Utility’s share of the procurement at 2,302 MW of incremental net qualifying capacity.

On April 21, 2022, the CPUC approved a group of nine long-term RA agreements to meet a portion of the Utility’s procurement requirements under the CPUC’s mid-term reliability decision. The agreements are each for a term of 15 years and collectively expected to supply 1,598.7 MW of lithium-ion energy storage capacity with some projects expected to be operational in 2023 and others in 2024.

OIR to Revisit Net Energy Metering Tariffs

On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers.

On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

On January 18, 2023, intervenors filed an application for rehearing. On February 2, 2023, the Utility filed a response to the application for rehearing.

Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter.

On December 13, 2022, the Utility filed applications with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation.

On January 20, 2023, the CPUC issued a scoping memo pursuant to which a PD would be issued by November 2023.

Self-Reports to the CPUC

The Utility self-reports potential violations of certain requirements to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these potential violations, including under the EOEP. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

Electric Asset Inspections

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, accordingly, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. In addition to its plan to complete the intrusive tests by September 30, 2023, the Utility is performing an end-to-end assessment of the wood pole test and treat program to proactively identify and address potential issues.

The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

Order Instituting an Investigation into PG&E Corporation’s and the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the “Safety Culture OII”). The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The SED engaged a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment, and subsequently, to report on the implementation by the Utility of the consultant’s recommendations.

On June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking the Utility’s rate of return or ~~return on equity~~ROE to safety performance metrics. ~~Opening comments on the ruling were filed on July 19, 2019 and reply comments were filed on August 2, 2019.~~

On September 4, 2020, the ~~ALJ~~administrative law judge issued a ruling updating case status, which states that the proceeding will remain open as a vehicle to monitor the progress of the Utility in improving its safety culture and to address any relevant issues that arise, with the CPUC’s consultant ~~NorthStar Consulting Group, Inc.~~ continuing in a monitoring role. The ruling states that additional issues may be raised in the proceedings by parties or the CPUC.

~~REGULATORY MATTERS~~

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

~~Rate Cases~~

~~2020 Cost of Capital Proceeding~~

On December 19, 2019, the CPUC approved a final decision in the 2020 Cost of Capital proceeding, maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020, as compared to 12% requested by the Utility. The Utility’s annual cost of capital adjustment mechanism, which allows for changes in the Utility’s authorized ROE and cost of debt, also remains unchanged. In any year in which the difference between the average Moody’s utility bond rates, as measured in the 12-month period from October through September, and 4.5% (the benchmark) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility can initiate this adjustment mechanism by filing an advice letter on or before October 15, to become effective on January 1 of the next year. The mechanism did not trigger in September 2020; however, as of December 31, 2020, the index is more than 100 basis points below the 4.5% benchmark. If the mechanism triggers in October 2021, then for 2022 the ROE and the cost of debt will be adjusted accordingly. The decision maintains the common equity component of the Utility’s capital structure at 52%, as requested by the Utility, and reduces its preferred stock component from 1% to 0.5%, also as requested by the Utility. The decision also approves the cost of debt requested by the Utility.

On May 28, 2020, the CPUC issued a decision in the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization that directed the Utility to submit an Advice Letter to update its authorized cost of debt within 30 days of the Effective Date of the Plan. On July 22, 2020, the Utility submitted an Advice Letter requesting to update the authorized cost of long-term debt to implement the interest cost savings resulting from the Utility’s exit financing. On August 20, 2020, the CPUC approved the Utility’s request to update the authorized cost of long-term debt from 5.16%, as authorized in December 2019, to 4.17% effective July 1, 2020.

~~2017 General Rate Case~~

As previously disclosed, on September 13, 2019 the Utility submitted an advice letter containing a revised computation of its revenue requirement due to the effects of the Tax Act, which indicated a $282 million net reduction to the 2018 revenue requirement and a $291 million net reduction to the 2019 revenue requirement. The revised gas revenue requirements increased by $21 million and $11 million for years 2018 and 2019, respectively, and the revised electric revenue requirements decreased by $304 million and $302 million for years 2018 and 2019, respectively. On October 17, 2019, the CPUC approved the Utility’s advice letter. The Utility incorporated the gas revenue requirement increases into rates through its Annual Gas True-up advice letter beginning on January 1, 2020 and amortized over 12 months. The Utility incorporated the electric revenue requirement reductions into rates through its Annual Electric True-up advice letter beginning on May 1, 2020. The Utility incorporated the total $606 million electric revenue requirement reduction as follows: (i) $175 million related to electric generation was amortized over 12 months, (ii) the 2018 revenue requirement reduction of $215 million related to electric distribution was amortized over 10 months, and (iii) the 2019 revenue requirement reduction of $216 million related to electric distribution was included in the Utility’s 2021 Annual Electric True-up beginning on January 1, 2021, to be amortized over 12 months. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

~~2020 General Rate Case~~

~~On December 3, 2020, the CPUC approved the final decision for the Utility’s 2020 GRC.~~

The final decision adopted most of the provisions in the settlement agreement that the Utility, together with the settling parties, jointly submitted to the CPUC on December 20, 2019 (the “settlement agreement”).

~~Revenue Requirements and Attrition Year Revenues~~

The final decision approved a 2020 authorized revenue requirement of $9.102 billion, an increase of $585 million over the 2019 authorized revenue requirement, effective January 1, 2020, as provided in the settlement agreement. The CPUC also approved the revenue requirements for 2021 and 2022 included in the settlement agreement as follows: an additional increase of $316 million in 2021 over the authorized 2020 revenue requirement, or a 3.5% increase, and an additional increase of $364 million in 2022, or a 3.9% increase. The revenue requirements will be further modified by advice letters to reflect an updated cost of debt, to remove certain customer deposits balances, and to return to customers the excess accumulated deferred income taxes that were created by the passage of the 2017 Tax Act. Subject to the CPUC approving the advice letters, the effective dates for the 2021 and 2022 attrition year revenue requirements will be March 1, 2021, and January 1, 2022, respectively. The 2021 attrition year revenue requirement will not be implemented in rates until March 1, 2021. The Utility is authorized to collect in rates the difference between the revenue requirement in effect and the 2020 GRC decision-authorized revenue requirement for the period of January 1, 2020 to February 28, 2021 over the period of March 1, 2021 through December 31, 2022.

The final decision also approves, among other things, the settlement agreement provision that allows the Utility to recover the annual cost of excess liability insurance for coverage of up to $1.4 billion. An advice letter is required for recovery of excess liability insurance costs for coverage exceeding $1.4 billion. The final decision also approved wildfire mitigation capital expenditures in the Community Wildfire Safety Program of $603 million in 2020, $931 million in 2021 and $1.15 billion in 2022, as provided in the settlement agreement. In addition, the final decision requires a reasonableness review and recovery of WMBA costs or unit costs for system hardening in excess of 115% of the adopted amounts and VMBA costs in excess of 120% of the adopted amounts through an application.

The following table shows the revenue requirement amounts approved in the final decision based on line of business and cost category as well as the differences between the 2019 authorized revenue requirements and the amounts approved in the final decision:

(in millions)
Lines of Business: Amounts Approved
in Final Decision Increase/ (Decrease)
2019 vs. Final Decision
Electric distribution $ 4,800 $ 436
Gas distribution 2,013 51
Electric generation 2,289 98
Total revenue requirements $ 9,102 $ 585
Cost Category:
Operations and maintenance $ 2,073 $ 128
Customer services 277 (61)
Administrative and general 1,203 250
Less: Revenue credits (195) (42)
Franchise fees, taxes other than income, and other adjustments 214 32
Depreciation (including costs of asset removal), return, and income taxes 5,530 278
Total revenue requirements $ 9,102 $ 585

~~Rate Base and Capital Additions~~

The CPUC also adopted the rate base amounts proposed in the settlement agreement: the 2019 weighted-average rate base of $27.7 billion was increased by $1.7 billion, effective January 1, 2020, to $29.5 billion, or a 6.2% increase; rate base of $31.0 billion in 2021, or a 5.4% increase; and $33.0 billion in 2022, or a 6.3% increase. Consistent with AB 1054, the adopted rate base amounts include $140 million for August to December 2019, $603 million for 2020, $931 million for 2021 and $1.15 billion for 2022, for a total of $2.83 billion in forecast capital spend without an equity return.

Over the 2020-2022 GRC period, the decision provides average annual capital investments of approximately $4.5 billion in electric distribution, natural gas distribution and electric generation infrastructure.

Consistent with the Utility’s GRC application, the settlement agreement did not propose funding for claims resulting from the 2017 Northern California wildfires or the 2018 Camp fire. Also, the Utility did not seek recovery of compensation for PG&E Corporation’s and the Utility’s officers.

~~2023 General Rate Case~~

In accordance with a January 16, 2020 CPUC decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, the Utility is required to file with the CPUC on June 30, 2021 a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years. The Utility expects to file the 2023 GRC by June 30, 2021.

On June 30, 2020, the Utility filed the 2020 RAMP Report in advance of its 2023 GRC filing. On November 25, 2020, the CPUC’s SPD released its evaluation of the Utility’s 2020 RAMP Report. The SPD found that “[t]he 2020 RAMP showed marked improvements in risk modeling rigor, data quality, and transparency over previous rate cases,” but cautioned that the Utility’s “track record calls for continued improvements by PG&E and continued rigorous oversight by the Commission.” The SPD held a workshop on its evaluation of the Utility’s RAMP on December 8, 2020, and opening and reply comments were submitted on January 15, 2021 and January 29, 2021, respectively.

~~2015 Gas Transmission and Storage Rate Case~~

As previously disclosed, in its final decisions 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 $373.3 million in revenue associated with $512 million of recorded capital expenditures. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.

On November 10, 2020, the Utility filed a motion seeking approximately $100 million in interim rates, assuming the CPUC reaches a final decision in this matter in late 2021 or early 2022. The CPUC has not yet ruled upon the Utility’s motion.

~~The Utility is unable to predict the timing and outcome of this application.~~

As previously disclosed, as a result of the Tax Act, on October 17, 2019, the CPUC approved the Utility’s advice letter including a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $61 million reduction to the 2018 revenue requirement. The Utility incorporated the revenue requirement reduction into rates through its Annual Gas True-up advice letter beginning January 1, 2020 and amortized over 12 months. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

~~2019 Gas Transmission and Storage Rate Case~~

As previously disclosed, on September 12, 2019, the CPUC voted out the final decision in the 2019 GT&S rate case of the Utility. By approving the decision, the CPUC adopted a 2019 revenue requirement of $1.332 billion compared to the Utility’s (revised) request of $1.485 billion. This corresponds to an increase of $31 million over the Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The CPUC also adopted revenue requirements of $1.432 billion for 2020, $1.516 billion for 2021, and $1.580 billion for 2022, compared to the Utility’s request of $1.595 billion for 2020, $1.693 billion for 2021, and $1.679 billion for 2022.

As previously disclosed, on October 23, 2019, the Utility filed an application with the CPUC requesting the rehearing of the final decision. Specifically, issues identified by the Utility include the adopted disallowance associated with vintage pipe replacement, reduction in the Utility’s expense forecast for in-line inspections, and establishment of a memo account for Internal Corrosion Direct Assessment. The Utility cannot predict the timing and outcome of this matter.

As previously disclosed, on January 16, 2020, the CPUC approved a final decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, as a result of which the Utility will be required to combine the GRC and GT&S rate cases starting with the 2023 GRC. In accordance with the decision, on June 30, 2021, the Utility is required to file with the CPUC a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.

~~Transmission Owner Rate Cases~~

~~Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)~~

As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Court of Appeals’ opinion.

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder. On August 16, 2019, a number of parties filed for rehearing of that order.

On March 17, 2020, the FERC issued its order denying the requests for rehearing. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals. The Utility submitted briefing on November 12, 2020 and the briefing on the appeal was completed on December 2, 2020. The Utility is unable to predict the timing and outcome of this proceeding.

~~Transmission Owner Rate Case for 2017 (the “TO18” rate case)~~

As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network transmission rate base for 2017 was $6.7 billion. The Utility sought a ROE of 10.9%, which included an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted that it would make investments of $1.30 billion in 2017 in various capital projects.

Also, as previously disclosed, on October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.9%, and an estimated composite depreciation rate of 2.96% compared to the Utility’s request of 3.25%. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility’s rate base and revenue requirement. Finally, the ALJ 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. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ’s initial decision.

On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, which refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs and testimony were filed on December 14, 2020 and responses were filed on February 12, 2021. The Utility’s initial brief requested a ROE of 13.29%. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the order reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order 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. Aside from the ultimate outcome of the common plant allocation and ROE methodology, which is subject to further briefing, the FERC’s October 15, 2020 order is not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s current formula rate, described below under the TO20 rate case.

On November 16, 2020, the Utility submitted a request for rehearing of certain rulings in the FERC’s October 15, 2020 order. The Utility requested in its application, among other things, that the FERC allow the Utility to demonstrate that the common, general and intangible plant costs actually occurred. Two intervenors in the case also filed for rehearing on net salvage value and the applicability of the Tax Act to the Utility’s rates. On December 17, 2020, the FERC denied all the pending requests for rehearing. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties.

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

~~Transmission Owner Rate Case for 2018 (the “TO19” rate case)~~

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case with the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 was $6.9 billion. The Utility sought a ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion.

Also, as previously disclosed, on September 21, 2018, the Utility filed an all-party settlement with the FERC 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 the issuance of a final, non-appealable TO18 decision. Additionally, if the Court of Appeals were to determine that the Utility was not entitled to the 50 basis point incentive adder for the Utility’s continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. See Transmission Owner Rate Cases for 2015 and 2016 above for a discussion of the incentive adder. On December 20, 2018, the FERC issued an order approving the all-party settlement.

~~Transmission Owner Rate Case for 2019 (the “TO20” rate case)~~

As previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case with the FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the Effective Date for rate changes. The FERC also ordered that the hearings be held in abeyance pending settlement discussions among the parties.

The formula rate replaces the “stated rate” methodology that the Utility used in its previous TO rate case filings. The formula rate methodology still includes an authorized revenue requirement and rate base for a given year, but it also provides for an annual update of the following year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements are updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate are either collected from or refunded to customers.

On March 31, 2020, the Utility filed a partial settlement with the FERC that resolves issues regarding the inputs, and methods used in the formula rate consistent with FERC precedent. In addition, the partial settlement establishes a stakeholder transmission asset review process that allows the stakeholders to review transmission capital projects that are not subject to review under the CAISO Transmission Planning Process which would be included in TO rates; allows the Utility to resolve the issue of compliance to reconcile the rate base with the CAISO register data base; and requires the Utility to seek the FERC’s authorization before recovering claims related to the 2017 Northern California wildfires and the 2018 Camp fire. The partial settlement was approved by the FERC on August 17, 2020.

On October 15, 2020, the Utility filed a settlement with the FERC resolving all of the remaining issues in the Formula Rate Proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement establishes an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing to be effective on January 1, 2024. The settlement also requires the Utility to concurrently file a motion for interim rates requesting that the settlement rates go into effect on January 1, 2021 while approval of the settlement is pending at the FERC. Also as part of the settlement, the Utility made supplemental filings to revise its request in two FERC dockets on October 15, 2020 addressing the calculation of the Utility’s AFUDC to reflect the terms of the settlement.

On December 30, 2020, the FERC approved the October 15, 2020 settlement without modifications. Also, on December 30, 2020, the FERC approved the two AFUDC dockets addressing the calculation of the Utility’s AFUDC calculation without modifications.

~~Nuclear Decommissioning Cost Triennial Proceeding~~

~~While the Utility expects active decommissioning to begin soon after expiration of the current operating licenses, the Utility expects that the decommissioning~~Extension of Diablo Canyon will take many years. Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory, site restoration, and remediation requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

As previously disclosed, on December 13, 2018, the Utility submitted its 2018 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion to decommission the Diablo Canyon facilities.

Also, as previously disclosed, on January 10, 2020, the settlement agreement that the parties had reached in this proceeding was filed with the CPUC, along with a joint motion for adoption of the settlement agreement.

Under the proposed settlement agreement, the Utility would collect annual revenue requirements of $112.5 million and $3.9 million for the funding of the Diablo Canyon non-qualified trust and Humboldt Bay tax qualified trust, respectively, commencing January 1, 2020. Additionally, under the proposed settlement agreement, the $398.4 million spent for Humboldt Bay Power Plant decommissioning project costs completed to date would be deemed reasonable.

~~On February 22, 2021, the CPUC extended the statutory deadline to resolve this proceeding to September 13, 2021. A proposed decision is expected in the fourth quarter of 2021.~~

~~Application for Wildfire Mitigation and Catastrophic Events Interim Rates~~

On February 7, 2020, the Utility filed an interim relief application seeking $899 million in interim rates related to certain electric distribution costs recorded in the following memorandum accounts: WMPMA, FRMMA, FHPMA, and CEMA. The costs pertain mainly to the years 2017-2019. The application addresses costs recorded in: (i) the WMPMA and FRMMA to comply with the 2019 WMP and other wildfire mitigation costs not otherwise recoverable through rates, (ii) the FHPMA to comply with various fire safety rulemakings through 2019, and (iii) the CEMA for responding to, and restoring customer service after, certain storms and fires occurring in 2017-2019.

The Utility submitted a request on March 23, 2020, to reduce the interim rate relief by $8.4 million. This reduction, which reduces the requested rate relief to $891 million, relates to the capital cost reduction required by AB 1054.

On October 22, 2020, the CPUC voted out its final decision that approved interim relief in the amount of $447 million. The Utility will recover these costs over a 17-month period beginning in January 2021.

~~Wildfire Mitigation and Catastrophic Events Costs Recovery Application~~Operations

On September ~~30, 2020,~~2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility ~~filed an application with the CPUC requesting cost recovery~~would continue to operate Diablo Canyon on behalf of ~~recorded expenditures related to wildfire mitigation, certain catastrophic events,~~all CPUC-jurisdictional LSEs, and ~~a number~~all customers of other activities (the “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 revenue requirement of approximately $1.28 billion.

~~The costs addressed in the 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. The requested revenue for CEMA costs reflected in the application include the Utility’s costs incurred responding to ten catastrophic events, including the 2017 Tubbs fire.

In its application, the Utility proposed the following ratemaking scenario: given the CPUC approval of $447 million in interim rate relief which includes interest, the Utility proposed to recover the remaining $868 million revenue requirement, including interest, over a one-year period (following the conclusion of interim rate relief recovery). Cost recovery requested in this application is subject to the CPUC’s reasonableness review.

~~On December 23, 2020, the assigned commissioner issued a scoping memo and ruling for the proceeding, which calls for a proposed decision to~~LSEs would be ~~issued in September 2021.~~

The Utility is unable to predict the outcome of this application. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs included in this application.

For more information regarding the FHPMA, the FRMMA, the WMPMA, and the CEMA memorandum accounts, see “Wildfire Mitigation Memorandum and Balancing Accounts” and “Catastrophic Event Memorandum Accounts and Applications” below.

~~Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account~~

~~On February 7, 2020, the Utility filed an application seeking recovery of certain costs recorded in the WEMA. In the application, the Utility seeks recovery of $498.7 million~~responsible for the cost of ~~insurance premiums paid by~~extended operations. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility ~~between July 26, 2017 through December 31, 2019 that~~from the DWR to support the extension of plant operations, which is ~~incremental~~in addition to the ~~insurance costs already authorized~~amount discussed in the 2017 GRC or the 2020 GRC. These incremental costs are not associated with any specific wildfire event. The application does not seek recovery of wildfire claims or associated legal costs eligible for recording to WEMA.

On April 2, 2020, the CPUC held a prehearing conference in this matter. On January 12, 2021, the CPUC issued a scoping memo establishing the scope and schedule for the proceeding. As amended by subsequent rulings, the schedule calls for a final decision in August 2021. The Utility cannot predict the outcome of this proceeding.

~~Catastrophic Event Memorandum Accounts and Applications~~

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed“Assembly Bill 180”, below. SB 846 further directs the Utility to ~~perform additional fire prevention~~take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and ~~vegetation management work in response~~any other potentially available federal funding, to repay the ~~severe drought in California.~~loan. The ~~costs associated with this work are tracked in the CEMA. In the 2020 GRC Decision, the CPUC required~~loan may be forgiven under certain circumstances. On October 18, 2022, the Utility ~~to track these costs in~~executed the ~~VMBA beginning January 1, 2020. The Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 4 of~~loan agreement with the ~~Notes to the Consolidated Financial Statements in Item 8.~~

~~2019 CEMA Application~~DWR.

On September ~~13, 2019,~~2, 2022, the Utility ~~submitted~~applied for federal funding through the DOE’s Civil Nuclear Credit Program. On November 17, 2022, the DOE conditionally selected the Utility to receive funding of up to $1.1 billion as part of the program. Final terms are subject to negotiation and finalization by the DOE. SB 846 provides that within 180 days of the filing of the DOE application, the CEC, in consultation with the CAISO and the CPUC, ~~its 2019 CEMA application requesting cost recovery~~shall make a determination in a public process of ~~$159.3 million~~whether the state’s electricity forecasts for the calendar years from 2024 through 2030 show potential for reliability deficiencies if Diablo Canyon operations are not extended beyond 2025 and whether extending operations of Diablo Canyon until 2030 is prudent to ensure reliability in ~~connection with 13 catastrophic events that included 12 wildfires and one storm~~light of any potential for ~~declared emergencies from mid-2017~~supply deficiency. During the quarter ended December 31, 2022, the Utility adjusted the ARO to reflect extended operations of Diablo Canyon through ~~2018. The 2019 CEMA application~~2030. However, the Utility’s ARO could be materially impacted if the Utility does not ~~include costs related to~~receive the ~~2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.~~required federal and state licenses, permits, and approvals.

~~On August 31, 2020~~During the ~~Utility, TURN~~period prior to extended operations, the bill authorizes a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon. The performance-based disbursement will be paid from the loan proceeds authorized by SB 846 and is contingent upon the ~~PAO filed a joint motion seeking approval~~Utility’s ongoing pursuit of extension of the operating period and ~~adoption of a settlement agreement reached between the settling parties.~~continued safe and reliable Diablo Canyon operations. The settlement agreement proposes a total revenue requirement of $136.7 million consisting of an expense revenue requirement of $112 million and a capital revenue requirement for 2017 through 2022 of $24.7 million.performance-based disbursement cannot be realized as shareholder profits or paid out as dividends.

~~On November 19, 2020,~~During the ~~CPUC issued~~period of extended operations and in lieu of the traditional rate-based return on investment, the bill provides for a ~~final decision adopting the settlement agreement.~~

~~2018 CEMA Application~~

~~On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery~~fixed payment of ~~$183~~$50 million, in ~~connection~~2022 dollars, for each of Diablo Canyon’s Unit 1 and Unit 2 for each year of extended operations to be recovered from customers of all CPUC-jurisdictional LSEs, which is potentially subject to adjustment downward in the event of extended unplanned outages. In addition, the bill authorizes a volumetric payment totaling $13, in 2022 dollars, for each MWh generated by Diablo Canyon during the period of extended operations, with ~~seven catastrophic events that included fire~~the first half recovered from all CPUC-jurisdictional LSEs and ~~storm declared emergencies~~the second half from ~~mid-2016 through early 2017, as well as $405 million related to work performed~~customers 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.~~

~~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, compared to $588 million requested by the Utility.~~service area. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On August 7, 2019, the Utility filed a revised application, revised testimony and revised workpapers, reflecting a new revenue requirement request of $669 million, pursuant to a CPUC ruling allowing these changes.

~~The 2018 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.~~

On March 9, 2020, the CPUC issued a modified scoping memo and ruling. On May 4, 2020, the Utility filed a revised application, which included 2019 tree mortality costs, reflecting a new revenue requirement request of $757 million, and the costs of an independent auditor to be hired for audit of all vegetation management costs and related interest calculations.

On January 8, 2021, the Utility filed a revised application updating the revenue requirement to include an additional $5.6 million of tree mortality costs and the cost of hiring an independent auditor.

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

~~Wildfire Mitigation Memorandum and Balancing Accounts~~

~~Fire Hazard Prevention Memorandum Account~~

The CPUC allows utilities to track and record costs associated with implementing 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. The Utility tracked such costs in the FHPMA through the end of 2019.

~~On December 17, 2019, the Utility, the SED~~amount of the ~~CPUC, the CPUC’s OSA,~~fixed and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agrees, among other things, to not seek recovery of $36 million of wildfire-related expenses recorded in the FHPMA. For more information on the settlement agreement, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Other than the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the Utility believes such costs are recoverable, but rate recovery requires CPUC reasonableness review.

The Utility requested recovery of costs recorded in the FHPMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application described above. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.)

~~The amount reflected in this memorandum account as of December 31, 2020 was $258 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Fire Risk Mitigation Memorandum Account~~

On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs incurred beginning January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was authorized to capture mitigation costs of activities not included in a CPUC approved WMP. The Utility has proposed that the FRMMA continue after the approval of its 2019 WMP to record costs of wildfire mitigation activities that were beyond the initial identified scope of work or are incurred prior to approval of the WMP in which they are proposed. The FRMMA includes costs associated with the 2019 WMP from the period January 1, 2019 through June 4, 2019, as well as subsequent wildfire mitigation costs not included in the WMPMA, discussed below. Recovery of costs are subject to CPUC review and approval. The Utilityvolumetric payments will ~~continue to use the FRMMA for new programs or expanded scope of existing programs before the WMP is approved.~~

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agreed, among other things, not to seek recovery of $236 million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For more information on the settlement agreement, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility requested recovery of costs recorded in the FRMMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application, except for the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.) PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be ~~materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP recorded in the FRMMA.~~

~~The amount reflected in this memorandum account as of December 31, 2020 was $99 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Wildfire Mitigation Balancing Account~~

In the 2020 GRC Decision, the CPUC authorized the Utility to establish the WMBA effective January 1, 2020, to track and record actual expenses incurred and the capital revenue requirement associated with actual capital additions incurred compared to the total adopted revenue requirements for specified wildfire mitigation activities, for the period beginning January 1, 2020. The WMBA is a two-way balancing account, which allows the Utility to seek cost recovery for amounts exceeding the approved revenue requirement, subject to a demonstration of reasonableness. The Utility is required to submit an application to the CPUC to recover the costs of program expenditures exceeding 115% of the adopted amounts or if the average overhead or underground system hardening per mile unit costs exceed specified unit costs by 115%.

~~The amount reflected in this balancing account as of December 31, 2020 was $183 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Wildfire Mitigation Plan Memorandum Account~~

As previously disclosed, on June 5, 2019, the Utility submitted an advice letter to establish the WMPMA (also called the Wildfire Mitigation Plan Memorandum Account) effective May 30, 2019. The WMPMA is required to be established upon approval of a utility’s WMP to track costs incurred to implement the Utility’s WMPs. The CPUC approved the memorandum account on August 8, 2019, so the Utility has recorded costs incurred in implementing the WMPs, as of June 5, 2019, the effective date of the WMPMA.

~~The Utility requested recovery of costs recorded in the WMPMA in its~~Wildfire Mitigation and Catastrophic Events Costs Recovery Application, except for the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.) PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP and the 2020 WMP recorded in the WMPMA.

~~The amount reflected in this memorandum account as of December 31, 2020 was $551 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Vegetation Management Balancing Account~~

~~The VMBA was approved~~adjusted annually by the CPUC using CPUC-approved escalation methodologies and adjustment factors. The volumetric payment cannot be realized as shareholder profits or paid out as dividends, to the extent it is not needed for Diablo Canyon. The legislation includes language that limits use of the volumetric payment to investments in the Utility’s 1999 GRC as a one-way balancing account mechanism to recover the costs of routine vegetation management expenditures, in an amount not to exceed the approved revenue requirement. In the 2020 GRC Decision, the CPUC authorized the Utility to modify the VMBA as a two-way balancing account, which allows the Utility to seek recovery of expenditures incurred above the revenue requirement, subject to a demonstration of reasonableness,system and for the period beginning January 1, 2020. The account was further modified to include the Utility’s new enhanced vegetation management program and additional vegetation management costs currently recorded in the CEMA for which there is no approved revenue requirement. The Utility is required to submit an application to the CPUC to recover the costs of program expenditures exceeding 120% of the adopted amounts. If the Utility’s expenditures are less than the approved revenue requirement, the Utility will return any over collection to customers ~~through an advice letter.~~that address critical state priorities.

The ~~amount reflected~~CPUC has initiated a rulemaking proceeding in ~~this balancing account as~~January 2023 to develop a new mechanism to recover costs from customers of ~~December 31, 2020 was $707 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Risk Transfer Balancing Account~~

~~In the 2020 GRC Decision, the CPUC authorized the Utility to establish the RTBA effective January 1, 2020, to track and record actual expenses incurred compared to the adopted revenue requirements~~all CPUC-jurisdictional LSEs for the ~~GRC portion~~continued operation of ~~excess liability insurance costs, inclusive of all financial risk transfer mechanisms (insurance, reinsurance, catastrophe bonds, captives),~~Diablo Canyon and ~~related costs (such as broker fees and excise taxes). The Utility would seek recovery of any risk transfer costs~~to address other issues associated with ~~coverage above $1.4 billion, through an advice letter.~~

~~The RTBA~~continued operation, including cost responsibility if Diablo Canyon is a two-way balancing account that tracks and records the GRC portion of actual financial risk transfer costs incurred compared to adopted amounts. Adopted amounts and actual costs incurred allocated to the Utility’s GT&S rate case and TO rate case will be recorded to authorized mechanisms applicable to those rate cases, specifically, the adjustment mechanism for GT&S-related amounts and the Utility’s FERC formula rates for TO related amounts.

~~For more information about the RTBA, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8.~~

~~Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections~~

In response to the COVID-19 pandemic, on April 16, 2020, the CPUC adopted a resolution ordering utilities to implement a number of emergency customer protections for one year beginning on March 4, 2020 through April 16, 2021, including:

•~~waive deposit requirements for residential customers seeking to reestablish service for one year;~~

•~~implement payment plan options for residential customers;~~

•~~suspend disconnection for nonpayment and associated fees, waive deposit and late fee requirements for residential and small business customers;~~

•~~support low-income residential customers by:~~

◦~~freezing all standard and high-usage reviews for the CARE program eligibility for 12 months and potentially longer, as warranted;~~

◦contacting all community outreach contractors, the community-based organizations that assist in enrolling hard-to-reach low-income customers into CARE, to help better inform customers of these eligibility changes;

◦~~partnering with the program administrator of the customer funded emergency assistance program for low-income customers and increasing the assistance limit amount for the next 12 months; and~~

◦~~indicate how the energy savings assistance program can be deployed to assist customers;~~

•suspend all CARE and Federal Emergency Relief Administration program removals to avoid unintentional loss of the discounted rate during the period for which the customer is protected under these customer protections;

•~~discontinue generating all recertification and verification requests that require customers to provide their current income information;~~

•~~offer repair processing and timing assistance and timely access to utility customers;~~

•~~include these customer protections as part of their larger community outreach and public awareness plans;~~

•~~meet and confer with the CCAs as early as possible to discuss their roles and responsibilities for each emergency customer protection.~~

The resolution also authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the resolution. On February 11, 2021, the CPUC approved a resolution extending the moratorium on service disconnections for residential and small business customers to June 30, 2021.

On June 11, 2020, the CPUC issued a final decision as part of the OIR to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs that permanently eliminated deposit requirements for residential customers. On December 21, 2020, a CPUC ALJ issued a ruling seeking comments on an approach to implement a temporary moratorium on service disconnections for medium-large commercial and industrial customers.

~~PG&E Corporation and the Utility are~~ unable to ~~predict whether this resolution will be extended or expanded to additional customer classes, which could have~~operate. The legislation also established a ~~material impact on results of operations, financial condition, and cash flows of PG&E Corporation and the Utility.~~

~~COVID-19 Pandemic Protections Memorandum~~$300 million Liquidated Damages Balancing Account

On May 1, 2020, the Utility submitted an advice letter to establish the CPPMA. The purpose of the CPPMA is to track costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 Pandemic. Costs included in the CPPMA will include incremental uncollectibles expense for residential and small business customers, incremental financing costs as a result of lower accounts receivable collections for residential and small business customers, and the costs of complying with various customer protections described in “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections,” above. The Utility intends to seek recovery of the CPPMA balance in a future application, recovery of which will require CPUC reasonableness review.

On June 2, 2020 and July 15, 2020, the Utility submitted updated advice letters to modify and clarify prior proposals based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter.

The amount reflected in this memorandum account as of December 31, 2020 was $84 million, of which $76 million relates to incremental uncollectible expenses. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

~~Other Regulatory Proceedings~~

~~Application to Sell General Office Complex~~

On September 30, 2020, the Utility filed an application with the CPUC to sell its SFGO located at 215 Market Street, 245 Market Street, 77 Beale Street, 50 Main Street, 25 Beale Street, and 45 Beale Street in downtown San Francisco, and to cover costs to relocate its staff at SFGO to a new headquarters to the Lakeside Building, and for appropriate ratemaking treatment of those transactions.

The Utility proposes the SFGO sale and headquarters transition proceed in several interrelated steps: the Utility has entered into a lease for the Lakeside Building with an option to purchase the Lakeside Building; the Utility will market and sell the SFGO, subject to CPUC approval; and the Utility will enter into an agreement with the buyer of the SFGO to lease back space during the multi-year relocation period (collectively, the “Transactions” (“LDBA”). 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 will 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.

In this application, the Utility requests that the CPUC: (i) authorize the Utility to sell the SFGO pursuant to Public Utilities Code section 851, (ii) approve the Utility’s ratemaking proposal to distribute all of the gain on sale of the SFGO to customers over five years, beginning in 2022, (iii) approve the recovery of costs to lease back the SFGO after the buildings are sold, costs to lease the Lakeside Building, and other transition costs, and (iv) authorize the Utility to forecast the intended purchase of the Lakeside Building and include it in the Utility’s 2023 GRC. The Utility also proposes to establish a balancing account to record lease payments, net savings or costs on operating expense and capital expense, gain on sale, moving costs and related costs for inclusion in electric and gas rates.

~~On December 1, 2020, the CPUC held a prehearing conference in this matter. On December 15, 2020, the assigned commissioner issued a scoping memo, which sets forth the category, issues~~ to be ~~addressed, and schedule of the proceeding.~~funded over time by all CPUC-jurisdictional customers. The ~~scoping memo contemplates~~LDBA provides a ~~CPUC final decision as early as August 2021 and provides~~source for ~~additional timeline flexibility depending on the pace of the sale process.~~

~~PG&E Corporation and the Utility are unable~~paying for replacement power costs, if incurred, due to ~~predict the timing and outcome of this proceeding.~~

~~Application for Post-Emergence Securitization Transaction~~

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. Among other uses,unplanned outages at Diablo Canyon as a result of the ~~proposed transaction,~~Utility’s failure to meet the CPUC’s reasonable-manager standard.

The key remaining steps to continued operations include NRC license renewal and approval from California state agencies. If either is not received, the Utility would retire ~~$6.0 billion~~Unit 1 in 2024 and Unit 2 in 2025 as previously approved by the CPUC. On October 31, 2022, the Utility requested that the NRC resume its review of a license renewal application the Utility ~~debt~~voluntarily withdrew and ~~accelerate a $592 million payment due~~terminated in 2018 or else grant an exemption to permit operations to continue at Diablo Canyon after the ~~Fire Victim Trust. Specifically,~~expiration of each of its current operating licenses and until the ~~application requests administration~~NRC completes its review of the ~~stress test methodology approved in~~license renewal application. On January 24, 2023, the ~~CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a securitization refers~~NRC staff declined to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposes a customer credit designed to equal the bond charges over the liferesume its review of the bond, which would insulate customers from the charge on customer bills associated with the bonds. The Utility proposes to fund the customer credit through a trust that consists of shareholder assets including: (1) an initial contribution of $1.8 billion; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; and (3) investment returns on the assets in the trust. The Utility also proposes to share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

~~Protests and response to the~~previously-withdrawn application ~~were due June 4, 2020 and the Utility filed a reply on June 12, 2020. A prehearing conference was held on June 18, 2020. The assigned commissioner issued the scoping memo on July 28, 2020~~ and directed the Utility to file updated testimony, if any, based on its post-emergence financial status by August 7, 2020. On August 7, 2020, the Utility served its updated testimony, in which it discussed, among other things, PG&E Corporation’s and Utility’s exit financings from Chapter 11 and related equity issuances, including to the Fire Victim Trust, in connection with consummating the Plan on July 1, 2020; issuance of revised credit ratings; updated financial forecasts for the Utility and their impacts on the securitization application, including on the stress test costs and the customer credit trust; and certain expected tax impacts.

Intervenor testimony was served on October 14, 2020, and the Utility’s rebuttal testimony was submitted on November 11, 2020. An evidentiary hearing was held on December 7-16, 2020. Opening briefs were submitted on January 15, 2021, and reply briefs were submitted on February 1, 2021. Insubmit a post-hearing briefing, the Utility and other parties in the proceeding included potential conditions and alternatives for the CPUC’s consideration. In post-hearing briefing, the Utility included an alternative proposal for the CPUC’s consideration comprised of four elements: (1) a $200 million increase in the initial shareholder contribution, from $1.8 billion to $2 billion, provided that $1 billion is contributed in 2021 and $1 billion in 2024; (2) potential shift in the customer credit trust’s investment portfolio to a greater proportion of fixed income investments; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) a reduced sharing of any trust surplus with customers to 10%. The Utility anticipates a CPUC decision in the second quarter of 2021.

On January 6, 2021, the Utility filed an application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to securitize the $7.5 billion of claims associated with the 2017 Northern California Wildfires referenced above. On January 7, 2021, the Utility filed a motion to consolidate the pending application seeking authorization for a post-emergence transaction and thenew application for a financing order. The ALJ granted the Utility’s motion to shorten the time for protests to January 22, 2021, and the Utility filed a reply on February 1, 2021. A prehearing conference was held on February 5, 2021. On February 10, 2021, certain intervenors filed a joint motion to dismiss the Utility’s application for a financing order. On February 17, 2021, the Utility filed a response opposing the motion to dismiss. Also on February 17, 2021, the PAO filed a response supporting the motion to dismiss. The Utility expects a CPUC decision on the financing order by May 6, 2021.

~~Application for AB 1054 Securitization Transaction~~

On February 24, 2021 the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to a principal amount of approximately $1.19 billion related to fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021.  The $1.19 billion reflects capital expenditures related to the Utility’s Community Wildfire Safety Program, which were approved by the CPUC in the 2020 GRC, and include $655 million in recorded 2020 capital expenditures and an additional $535 million in forecast capital expenditures in 2021.  The final amount to be securitized would be based on recorded 2020 and 2021 Community Wildfire Safety Program expenditures incurred by the Utility.

The application requests that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest and would reduce rates on a present value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable recovery charge sufficient to pay debt service on the recovery bonds.  The application also requests to exclude the securitized debt from the Utility’s ratemaking capital structure and to adjust its GRC revenue requirement following the issuance of the recovery bonds.  The proposed procedural schedule requests a final decision on all issues by June 24, 2021 and the application indicates that the issuance of the bonds is anticipated to occur before the end of 2021, but is subject to change.

~~2019 Wildfire Mitigation Plan~~

As previously disclosed, on October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility WMPs. This OIR provided guidance on the form and content of the initial WMPs, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of WMPs to be filed in future years. In this proceeding the CPUC determined, among other things, how to interpret and apply SB 901’s list of required plan elements, as well as what additional elements beyond those required in SB 901 should be included in the WMPs. SB 901 also requires, among other things, that such plans include a description of the preventive strategies and programs to be adopted by an electrical corporation to minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including the consideration of dynamic climate change risks, plans for vegetation management, and plans for inspections of the electrical corporation’s electrical infrastructure. The scope of this proceeding does not include utility recovery of costs related to WMPs, which SB 901 requires to be addressed in separate rate recovery applications.

On February 6, 2019, the Utility filed its first WMP, the 2019 WMP, with the CPUC, and amended it subsequently on February 12, 2019 and February 14, 2019. On May 30, 2019, the CPUC approved the 2019 WMP. (The Utility also filed an amendment to the plan on April 25, 2019, but CPUC approval did not extend to that amendment.)

~~2020-2022 Wildfire Mitigation Plan~~

As previously disclosed, on February 7, 2020, the Utility submitted its 2020 WMP and utility survey. The Utility’s 2020 WMP describes the Utility’s wildfire safety programs, which are focused on three key areas: reducing the potential for fires to be started by electrical equipment, reducing the potential for fires to spread, and minimizing the frequency, scope and duration of Public Safety Power Shut-off events, as well as providing historical data requested by the guidelines. The Utility’s 2020 WMP covers a three-year period from 2020-2022 but is updated annually.

On March 18, 2020, the CPUC issued a decision in this proceeding, clarifying that the CPUC’s newly created WSD would review 2020 WMPs, present resolutions for CPUC consideration on the 2020 Plans, and oversee independent evaluation and other compliance activity with regard to both 2019 and 2020 Plans.

On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved the Utility’s 2020 WMP. The resolutions indicate that while the Utility’s 2020 WMP met the minimum requirements for its submission, the deficiencies found, classified as severity level A, B, or C Conditions, require significant follow-up from the Utility and oversight to ensure appropriate remedies for the deficiencies. The Utility received 41 Conditions in total with the first set, classified as Class A Conditions, submitted on July 27, 2020. The second set, Class B Conditions, were completed on September 9, 2020 and the third, Class C Conditions, were submitted as part of the 2021 WMP update on February 5, 2021. On December 30, 2020, the WSD issued a Notice of Non-Compliance finding that the Utility’s responses to the Class A Conditions were insufficient. The WSD has required the Utility to include 39 action items in its 2021 WMP to address the insufficient responses. On January 8, 2021, the WSD issued a Notice of Non-Compliance finding that the Utility’s quarterly report addressing the Class B Conditions was insufficient. The WSD has directed the Utility to respond to 84 action items in its 2021 WMP or via a supplemental filing by February 26, 2021. Failure to remedy insufficiencies in the 2020-2022 WMP could lead to enforcement actions by the CPUC, including potentially placing the Utility in the Enhanced Oversight and Enforcement Process, and making the Utility unable to obtain an AB 1054 safety certification and, as a result, unable to access the Wildfire Fund, which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The Utility’s 2021 WMP was submitted on February 5, 2021. The 2021 WMP was an update to the 2020 WMP and addressed the Utility’s wildfire safety programs focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread, and making PSPS events smaller, shorter and smarter for customers.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP, 2020 WMP, and 2021 WMP recorded in the FRMMA and WMPMA,license renewal, which the Utility expects to do by the end of 2023. The NRC staff has stated that it will ~~be substantial.~~provide a response to the Utility’s request for an exemption in March 2023. Consistent with SB 846, the CPUC, the CEC, California State Lands Commission, California Coastal Commission, and other state agencies will need to determine that extended operations represent an appropriate path to meet California’s reliability, affordability, and environmental goals.

~~OIR Regarding Microgrids~~

As previously disclosed, on September 19, 2019, the CPUC initiated a rulemaking proceeding to examine microgrid implementation issues and resiliency strategies pursuant to SB 1339. In the first track of that proceeding, the CPUC sought to deploy resiliency planning in areas that are prone to outage events and wildfires, with the stated goal of putting some microgrid and other resiliency strategies in place by spring or summer 2020, if not sooner. At the CPUC’s direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility’s proposal contained three components for which it sought scope and cost recovery authorization of up to approximately $379 million in both expense and capital. On April 1, 2020, the Utility filed a motion seeking to supplement its original proposal and to reduce the total cost recovery authorization it was seeking to approximately $257 million. The Utility described in its supplemental testimony that it was focusing in 2020 on the use of temporary, mobile generation solutions to power microgrids in 2020, and that the Utility had suspended its solicitation for permanent generation located at substations with online dates in 2020. The Utility subsequently closed its solicitation for this permanent generation. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying the Utility’s motion to supplement its proposal.

The CPUC adopted a decision in the first track of the proceeding on June 11, 2020 (the “Track 1 Decision”), which approved with conditions the Utility’s proposal and requires the Utility to track costs in a new memorandum account for subsequent regulatory review and recovery in rates.

The CPUC initiated the second track of the proceeding on July 3, 2020, which focused on further implementation of SB 1339, as well as activity to shape the transition from diesel mobile generation to alternative, cleaner backup power generation. On January 14, 2021, the CPUC adopted a final decision in the second track of the proceeding (the “Track 2 Decision”). The Track 2 Decision requires the Utility to submit an Advice Letter to justify the amount of temporary generation necessary for use at substations during the 2021 wildfire season; to identify at least one clean substation project to pilot the use of diesel generation alternatives to power substation-level microgrids; to file an application by June 30, 2021 to propose a longer-term framework for substation generation solutions to mitigate PSPS outage events; and to file an application by September 30, 2021 to recover the costs incurred in 2020 associated with the use of temporary generation to mitigate PSPS outages. The Track 2 Decision also authorizes the Utility to record the future costs of temporary generation for substations in a memorandum account, with recovery of those costs through the general rate case or a separate application. The costs for the clean substation project(s) are authorized to be recovered through a one-way balancing account established by the Track 2 Decision, up to a $350 million cap and subject to other eligibility requirements.

In addition, the Track 2 Decision requires that the Utility: (1) modify its existing electric rules to allow certain critical facilities to be powered during grid outages by adjacent premises; (2) establish a new tariff to facilitate the commercialization and development of single-customer, single-account microgrids; (3) develop a new microgrid incentive program that compliments the Utility’s existing Community Microgrid Enablement Program and expands the incentives available for certain eligible community microgrids up to a statewide combined budget of $200 million; and (4) create a new process and associated criteria to evaluate technologies to isolate customer electrical loads for the purpose of forming microgrids during grid outages. The Track 2 Decision establishes an agenda for ongoing meetings of the CPUC’s Resiliency and Microgrids Working Group.

On February 9, 2020, the CPUC issued an amended scoping memo initiating Track 3 of the proceeding. In Track 3, the CPUC intends to address whether utilities, including the Utility, should waive standby charges for a customer operating a microgrid under certain circumstances. Further, the CPUC states that in a future Track 4 of the proceeding, it intends to address: (1) multi-property microgrid tariffs and alternatives; (2) methodologies to value resiliency; (3) microgrid interconnection issues; and (4) revisit its initial determinations with regard to a single-property microgrid tariff.

~~Failure to obtain a substantial or full recovery of costs could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.~~

~~OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization~~

As previously disclosed, on October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications “that will result from the confirmation of a plan of reorganization and other regulatory approvals necessary to resolve” the Chapter 11 Cases (the “Chapter 11 Proceedings OII”).

On May 28, 2020, the CPUC approved a final decision in this proceeding. As previously disclosed, the decision approved the Plan with certain conditions and modifications related to certain topics, including but not limited to, governance, operational structure, safety performance, executive competition, and financial condition. On September 17, 2020, the CPUC issued a proposed decision that would close the proceeding. On October 22, 2020, the CPUC approved the decision.

~~Enhanced Oversight and Enforcement Process~~

In the Chapter 11 Proceedings OII final decision, the CPUC adopted an Enhanced Oversight and Enforcement Process designed to provide a roadmap for how the CPUC will monitor the Utility’s performance on an ongoing basis. The Enhanced Oversight and Enforcement Process contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics (some of which will be determined in an ongoing regulatory proceeding). The Enhanced Oversight and Enforcement Process also contains provisions for the Utility to cure and permanently exit the Enhanced Oversight and Enforcement Process if it can satisfy specific criteria. If the Utility is placed into the Enhanced Oversight and Enforcement Process, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The Enhanced Oversight and Enforcement Process does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and Orders Instituting Investigations and to impose fines and penalties. The Enhanced Oversight and Enforcement Process requires the Utility to report the occurrence of a triggering event to the CPUC’s Executive Director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

On November 24, 2020, the Utility received a letter from the President of the CPUC, expressing concerns related to the Utility’s vegetation and asset management activities and explaining potential implications with respect to the CPUC’s Enhanced Oversight and Enforcement Process, as well as the Utility’s annual safety certification under California AB 1054. According to the Letter, the President of the CPUC has “directed CPUC staff to conduct fact-finding to determine whether a recommendation to place [the Utility] into the enhanced oversight and enforcement process is warranted.”

~~The Utility is unable to predict whether additional fines, penalties, or other regulatory actions may be taken.~~

~~Regionalization Proposal~~

On June 30, 2020, the Utility filed its application for approval of its Regionalization Proposal with the CPUC. The Utility’s proposal would divide its service area into five new regions to further improve safety and reliability, core operations, and be more responsive to the needs of its customers. The Utility’s Regionalization Proposal describes the development of these regions, plans to hire new regional leadership, and a new regional organization structure. The Utility’s application requests the CPUC to approve a memorandum account to record any incremental costs the Utility incurs in connection with the development and implementation of regionalization. The Utility will file an updated Regionalization Proposal with the CPUC on February 26, 2021.

~~The Utility is unable to predict the timing and outcome of this application.~~

~~Wildfire Fund Non-Bypassable Charge~~

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of an NBC to support the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision finding that the imposition of the NBC is just and reasonable. In addition, the decision affirmed that the Utility and its customers will not pay an allocated share of the adopted wildfire charge revenue requirement unless and until the Utility participates in the Wildfire Fund. The decision also continues the same allocation of the wildfire charge revenue requirement among the IOUs as previously adopted for the Department of Water Resources power and bond charge revenue requirements. The decision proposes revenue requirements for the Utility of $404.6 million, which is based on average annual collections and shall expire at the end of the year 2035.

On November 25, 2019, an individual intervenor filed an application for rehearing of the decision arguing that the decision constitutes a constitutional violation of procedural due process and an unjust and unreasonable rate increase. On March 2, 2020, the CPUC issued a decision denying the application for rehearing.

On July 16, 2020, the CPUC approved the Wildfire Fund NBC servicing orders between the California Department of Water Resources and the Large Electrical Corporations to impose the Wildfire Fund NBC. On September 10, 2020, the CPUC ordered the Utility to cease collection of the DWR Bond Charge related revenue requirement from electric customers in their respective territories. The final month in which a Bond Charge related revenue requirement was imposed to collect revenue from electric customers of the Utilities was September 2020.

~~On September 24, 2020, the CPUC ordered the Utility to collect the Wildfire Fund NBC from eligible customers from October 1, 2020 through December 31, 2020 in the amount of $0.00580 per kilowatt-hour.~~

On September 29, 2020, the Utility submitted an advice letter to submit tariffs incorporating final rates that was effective October 1, 2020. In addition to submitting tariff revisions that include final rates as outlined, the letter included the tariff revisions needed to cease the imposition of the DWR Bond Charge and implement the Wildfire Fund Charge.

On December 17, 2020, the CPUC approved the Utility to collect the Wildfire Fund NBC from eligible customers from January 1, 2021 through December 31, 2021 in the amount of $0.00580 per kilowatt-hour. On December 30, 2020, the Utility submitted an advice letter to submit tariffs incorporating final rates effective January 1, 2021. The advice letter is still pending CPUC approval.

On February 22, 2021, the CPUC issued a proposed decision regarding the amount of the Wildfire Non-Bypassable Charge in 2022 and 2023. The prehearing conference and scoping memo are expected to take place in April, 2021.

~~Transportation Electrification~~

As previously disclosed, on May 31, 2018, pursuant to a state law authorizing the Utility to conduct programs to support and incent the deployment of electric vehicles, the CPUC issued a final decision approving the Utility’s two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets.

On February 3, 2020, in a rulemaking to consider further utility-sponsored programs to support electric vehicles and transportation electrification, the CPUC issued a draft Transportation Electrification Framework for review and comment. The CPUC held workshops on the draft framework in 2020, and approval of the framework and guidance for future electric vehicle programs is expected in 2021.

Also in 2020, the California Legislature passed, and the Governor signed, a new law that authorizes the Utility and other California IOUs to invest in new electric distribution infrastructure to support electric vehicles without requiring electric vehicle customers to pay certain of the infrastructure costs that other customers are required to pay for non-electric vehicle infrastructure costs. Instead, the incremental electric vehicle infrastructure costs will be paid by the Utility’s electric customers as common utility costs in the Utility’s periodic general rate cases.

~~OIR to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas Planning~~

On January 16, 2020, the CPUC opened an OIR to address reliability and standards for gas public utilities, the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators, and impacts due to legislative mandates to address the GHG reduction emissions which will result in the replacement of gas-fuel technologies and forecast reduced demand for natural gas. This proceeding will examine whether recent industry related events will require the CPUC to change the rules, processes and regulations governing gas utilities, including but not limited to, gas reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders.

The Utility filed opening comments on the preliminary scope on February 26, 2020 and reply comments on March 12, 2020. The assigned ALJ and assigned commissioner held a prehearing conference on March 24, 2020. The Utility filed a post-prehearing conference statement on April 1, 2020. On April 23, 2020, the assigned commissioner issued a ruling setting the final scope, schedule and categorization for phase 1 (Tracks 1A and 1B). On July 7, the CPUC held a workshop to address natural gas reliability standards (Track 1A) and on July 21, 2020 a second workshop was held to address market structure and regulations (Track 1B). On October 2, 2020, the assigned ALJ issued a ruling, including the workshop report and staff recommendations. The Utility filed opening comments on the report on November 2, 2020 and filed reply comments on November 17, 2020. As directed in the October 2, 2020 ruling, the Utility held a workshop on November 30, 2020 to address intraday demand and grid reliability. On December 24, 2020, the ALJ issued a ruling that modified the schedule. The Utility filed its proposal to address gas supply and cost allocation issues described in the workshop report on January 8, 2021. Parties filed comments on January 29, 2021 and reply comments on February 12, 2021.

~~OIR to Consider Strategies and Guidance for Climate Change Adaptation~~

~~On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings.~~

On October 24, 2019, the CPUC adopted a final decision on a portion of phase one (Topic 1 and 2), defining climate change adaptation for California’s energy utilities as “adjustment in natural and human systems to a new or changing environment. Adaptation to climate change for energy utilities regulated by the CPUC refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climatic impacts and stimuli or their effects on utility planning, facilities maintenance and construction, and communications, to maintain safe, reliable, affordable and resilient operations.” In addition, this decision provides guidance on what data should be used by the IOUs to perform all climate impact, climate risk, and climate vulnerability analyses undertaken with respect to their infrastructure assets, operations, and customer impacts. Finally, this decision requires the energy utilities to adhere to the same climate scenarios and projections used in the most recent California Statewide Climate Change Assessment when analyzing climate impacts, climate risk, and climate vulnerability of utility systems, operations, and customers.

On October 22, 2019, the CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed each of the large IOUs to research and develop a new form of risk assessment, a CVA. CVAs instruct utilities to “examine the risks posed by climate change to their core lines of business, including generation, transmission, distribution, and storage, irrespective of who owns the assets.” In addition, the staff proposal provides guidance regarding the data sources to be used in the CVA, outreach and coordination with the community, and incorporation of CVA findings into RAMP and GRC filings. The Utility provided opening and reply comments on February 18, 2020 and March 3, 2020, respectively.

On August 27, 2020, the CPUC adopted a final decision on Topics 4 and 5, regarding adaptation outreach to disadvantaged communities and detailed requirements for each IOU’s CVA. The CPUC instructed each IOU to establish a “climate change team,” with cross-departmental responsibilities, which will report directly to a designated executive at the SVP level or above. Each IOU must disclose to the CPUC such changes in organizational structure, listing the individual names and department titles of all internal participants. Board members should oversee and prioritize climate adaptation planning, as informed by senior leadership. Each IOU is required to consider climate risks to assets, operations, and services over which IOUs have direct control. Additionally, the decision directs the IOUs to seek to obtain an acknowledgement in new contracts with third party providers that the operator has considered long-term climate risk. Each IOUs’ completed CVA will coincide with its RAMP filing during its four-year GRC cycle, and each IOU must detail resulting climate adaptation measures in a new chapter in its future GRC applications. Each IOU must file a Community Engagement Plan detailing community outreach on climate adaptation, covering every disadvantaged vulnerable community and leveraging existing IOU community outreach on other matters. The IOUs’ climate adaptation Community Engagement Plan proposals must be filed one year prior to their CVA, with the Utility’s first Community Engagement Plan due in June 2023, as the Utility’s first CVA under this decision will be due in June 2024. A new memorandum account, the Climate Adaptation Vulnerability Assessment Memorandum Account, was authorized to cover CVA costs and incremental costs of outreach.

~~OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions~~

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California.

On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8.

On January 30, 2020, the CPUC proposed new guidelines in phase two of this proceeding. On May 28, 2020, the CPUC adopted PSPS Phase 2 Guidelines, which require utilities to restore energy within 24 hours after the end of a PSPS event where possible; to consult with critical facilities on back-up power for PSPS events; and to support access and functional needs populations during PSPS events, including powering medical equipment at customer resource centers.

On August 24, 2020, the ALJ issued a decision addressing two joint motions that had been filed in the proceeding. The first motion filed on April 13, 2020 requested emergency protocols during the COVID-19 pandemic. The second motion filed on June 15, 2020 requested that the CPUC perform a reasonableness review of past IOU PSPS events to determine whether each was reasonable. The August 24, 2020 decision found that, with respect to the first joint motion, the May 28, 2020 decision dealt with many of the issues raised; and with respect to the second joint motion, the CPUC already performed reasonableness reviews of IOU PSPS events.

On December 2, 2020, the Utility and other parties submitted comments in this proceeding in response to an August 3, 2020 scoping ruling regarding SED’s report in a separate PSPS-related proceeding, OII to Examine the Late 2019 Public Safety Power Shutoff Events. In their comments, the Utility and other parties commented that issues raised in SED’s report should be addressed in a rulemaking setting. The Utility is unable to predict the timing and outcome of this proceeding.

On November 12, 2019, the assigned commissioner and ALJ issued an order to show cause directing the Utility to show why it should not be sanctioned for violations of law or CPUC decisions related to the PSPS events of October 9-12, 2019, October 23-25, 2019, and October 26-November 1, 2019.

The Utility submitted its testimony with the CPUC on February 5, 2020. Other parties submitted their testimony on February 28, 2020, and the Utility submitted its concurrent rebuttal testimony on April 7, 2020. On September 21, 2020, the assigned commissioner and the ALJ issued an order that required the Utility to respond to certain factual questions and concluded that with the provision of responsive answers to those questions, evidentiary hearings would not be needed in the proceeding. Opening briefs were filed on October 30, 2020, by all parties, which included an intervenor proposing financial penalties against the Utility of $166 million. If adopted by the CPUC, such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Reply briefs were filed by all parties on November 17, 2020, including the Utility, which opposed the imposition of any penalties.

On February 19, 2021, the CPUC proposed new guidelines in Phase 3 of this proceeding. If adopted, these guidelines would require utilities to submit annual pre- and post- season reports, have certain percentages of Community Resource Centers be indoors, have a webpage that explains “critical facility” requirements, and conduct de-energization simulation exercises. Parties will comment in March 2021, and a proposed decision is expected in May 2021, with a final decision in June 2021.

~~The Utility is unable to predict the outcome of this proceeding.~~

~~OII to Examine the Late 2019 Public Safety Power Shutoff Events~~

On November 13, 2019, the CPUC issued an OII to determine “whether California’s IOUs prioritized safety and complied with the CPUC’s regulations and requirements with respect to their PSPS events in late 2019.” The first phase of this proceeding focuses on (1) the effectiveness of the utility’s procedures to notify the public of the PSPS events, (2) the utility’s communication and coordination with first responders, local jurisdictions and state agencies, and (3) the utility’s management of its resources to ensure public safety. In later phases of this proceeding, the CPUC may consider taking action if it finds violations of statutes or its decisions or general orders have been committed and to enforce compliance, if necessary.

On June 8, 2020, the SED issued a public report on the Late 2019 Public Safety Power Shutoff Events. The report identified certain shortcomings in each of the electric IOUs’ implementation of the CPUC’s PSPS Guidelines during their late 2019 PSPS events but stated that its findings were intended to be advisory in nature, subject to modification, and not intended to serve as an adjudicatory staff investigatory pre-enforcement report. On August 3, 2020, the assigned commissioner issued a ruling and scoping memo directing parties to file comments on SED’s report and the following two issues: (1) whether the Utility and other IOUs in October and November 2019 complied with the criteria set forth in applicable laws and regulations when pro-actively deenergizing and re-energizing their power lines, and (2) what corrective actions the CPUC should require of the Utility and other IOUs for any failure in late 2019 to comply with the then-existing PSPS guidelines. Each of the IOUs filed their comments on September 2, 2020, intervenors filed their comments on October 16, 2020, and reply comments were filed by all parties on November 16, 2020. Several parties proposed in their comments that penalties be imposed on the utilities for inadequate implementation of the PSPS events. For example, TURN proposed that the CPUC should treat each customer affected by a PSPS event, for which the IOU has not adequately demonstrated that the benefits outweigh the public safety risks, as a separate offense, with each offense subject to a penalty of no less than $500 and no more than $100,000. In reply comments, the Utility argued that the proposed penalties should not be adopted for procedural and substantive reasons. If adopted by the CPUC, such penalties could be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

The proposed decision is expected in the first quarter of 2021, and the CPUC’s final decision is anticipated no sooner than 30 days after the proposed decision. The Utility is unable to predict the outcome of this proceeding.

~~Power Charge Indifference Adjustment OIR~~

In 2017, the CPUC initiated the PCIA Rulemaking to make refinements to the PCIA, a cost recovery mechanism to ensure that customers that leave the Utility’s bundled service for a non-Utility provider, such as a DA or CCA provider, pay their fair share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf. The above market costs of the Utility’s generation portfolio are calculated using benchmarks for energy, RA and RPS attributes.

As previously disclosed, on October 11, 2018, the CPUC approved a phase one decision to modify the PCIA methodology. The Utility implemented a revised PCIA reflecting this decision in rates as of July 1, 2019.

~~Also, as previously disclosed, on October 10, 2019, the CPUC approved a final decision that finalized the true-up for the new PCIA methodology.~~

On March 26, 2020, the CPUC approved a final decision on departing load forecasting and PCIA bill presentation issues, establishing that the IOUs shall show a PCIA line item in their tariffs and bill summary tables on all customer bills, which shall be implemented by the last business day of 2021.

On June 30, 2020, the CPUC issued a PD that would provide a non-Utility provider an option to prepay their entire PCIA obligation. On August 6, 2020 the CPUC issued a final decision adopting a framework for prepayment agreements for PCIA obligations.

The proceeding is now examining structures and rules governing how the Utility addresses excess resources in its portfolio due to load loss to CCA and DA, including standards for active management of the Utility’s portfolios. On December 16, 2020, the assigned commissioner issued an amended scoping memo and ruling expanding the rulemaking’s scope to include the potential modification of the annual PCIA rate cap and potential changes to the Utility’s cost recovery and rate setting proceedings to improve PCIA and ERRA alignment.

~~The Utility is unable to predict the outcome of this proceeding.~~

~~Central Procurement of the Resource Adequacy Program~~

On June 17, 2020, the CPUC issued a decision on the Central Procurement of the RA program. The decision shifts local RA procurement responsibility under the CPUC’s RA program from all load serving entities to a CPE in two distribution service areas, including the Utility’s distribution service area, resulting in a change from decentralized to centralized local RA procurement in those distribution service areas. The decision also adopted implementation details for the central procurement of multi-year local RA, ordered the Utility and another IOU to serve as the CPE for their respective distribution service areas, and adopted a hybrid central procurement framework for the multi-year local RA program beginning for the 2023 RA compliance year.

The decision requires the Utility, as the CPE for its distribution service area, to conduct a competitive, all-source solicitation for local RA procurement, with any existing local resource that does not have a contract, any new local resource that can be brought online in time to meet solicitation requirements, or any load serving entity or third-party with an existing local RA contract eligible to bid into the solicitation.

Subsequently, on December 3, 2020, the CPUC issued a follow-up decision adopting a compensation mechanism applicable to certain local resources that may be procured by the CPE for purposes of reducing the total CPE procurement requirements. This mechanism applies to new preferred local resources and new local energy storage resources, including utility-owned generation. Procurement by the Utility of, and compensation for, such resources shall occur outside of the competitive, all-source solicitation.

The Cost Allocation Mechanism methodology is adopted as the cost recovery mechanism to cover procurement costs incurred in serving the central procurement function. The administrative costs incurred in serving the central procurement entity function shall also be recoverable under the Cost Allocation Mechanism.

~~Integrated Resource Planning Procurement~~

On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision requires incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period 2021-2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision requires that at least 50% of LSE resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directs the IOUs to act as the backstop procurement agent for CCAs and Energy Service Providers (ESPs) that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision. On April 15, 2020, the ALJ issued a ruling that the Utility must procure 48.2 MWs of RA capacity for LSEs that chose to opt-out of voluntarily self-providing their required portion.

The Utility has procured its required RA capacity for the August 1, 2021 milestone from third parties through CPUC-approved contracts for lithium ion battery energy storage resources with terms ranging from 10-15 years. On December 22, 2020, the Utility filed an advice letter seeking CPUC approval of an additional group of similar contracts that would satisfy the balance of the Utility’s procurement obligations for the August 1, 2022 and August 1, 2023 milestones.

The CPUC is developing a Modified Cost Allocation Mechanism methodology, under which the Utility will be able to recover procurement and administrative costs it incurs in serving the backstop procurement function.

~~OIR to Further Develop a Risk-Based Decision-Making Framework for Electric and Gas Utilities~~

On July 20, 2020, the CPUC initiated a rulemaking proceeding to consider ways to strengthen the risk-based decision-making framework that regulated energy utilities use to assess, manage, mitigate and minimize safety risks. The rulemaking will build on requirements for a utility risk framework adopted in the first Safety Model Assessment Proceeding. The CPUC’s goal is to further the prioritization of safety by electric and gas utilities.

On November 2, 2020, the assigned commissioner issued a scoping memo establishing the scope, schedule, and categorization for Phase I and Phase II of the proceeding. Phase I, which began November 2020, will consider (i) clarifications to the technical requirements of the risk-based decision-making framework; (ii) safety and operational performance metrics; and (iii) refining RAMP procedural requirements.

On November 17, 2020, the assigned commissioner issued a ruling regarding the development of safety and operational metrics for the Utility. The ruling directed the Utility to propose metrics that are “suitable for the use as triggering events as specified in the Enhanced Oversight and Enforcement Process” and “suitable, over time, for the Commission, intervenors, and the public to potentially use to gauge the safety and operational performance of all gas and electric IOUs.” On January 15, 2021, the Utility filed a response proposing 12 safety and operational metrics using the criteria outlined by the ruling. On January 25, 2021, parties filed responses to the Utility’s proposal. On January 28, 2021, the CPUC hosted a public workshop where the Utility, the other IOUs, and intervenors commented on the Utility’s safety and operational metrics proposal. All parties may file comments on the Utility’s safety and operational metrics by March 1, 2021.

~~OIR to Revisit Net Energy Metering Tariffs~~

On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allows customer-sited renewable generation to grow sustainably among different types of customers.

On November 19, 2020, the assigned commissioner and the ALJ issued a scoping memo and ruling for this proceeding. The scoping memo separated the proceeding into two phases. In the first phase, the CPUC will address several issues including, but not limited to, determining the principles to assist in the development and evaluation of a successor to the current NEM tariffs, assessing what information from a study on existing tariffs should inform the successor, outlining the methods to use to analyze the program elements and the resulting proposals, and determining the program elements or specific features that should be included in the successor tariff. In the second phase, the CPUC will consider what additional or enhanced consumer protections for customers should be adopted, as well as other issues that may arise, such as the virtual net energy metering tariffs, NEM aggregation tariff, the Renewable Energy Self-Generation Bill Credit Transfer program, and the NEM fuel cell tariff.

On January 5, 2021, the ALJ issued a PD that outlined eight guiding principles to assist in the development and evaluation of proposals for successor to the current NEM tariff. The Utility filed comments on January 25, 2021, and reply comments on February 1, 2021. On February 11, 2021, the CPUC issued a final decision on the guiding principles.

~~OIR to Address Energy Utility Customer Debt Accumulated during the Coronavirus Pandemic~~

On February 11, 2021, the CPUC initiated a rulemaking proceeding to consider arrearage relief for utility customers who will have outstanding utility bills when the moratorium on service disconnections ends. The OIR will evaluate a more global program beyond the currently approved arrearage management program focused on low-income residential customers that is funded by the Utility’s customers. The OIR may consider various funding approaches for this expanded debt forgiveness proposal, which could include shareholder funding.

~~The CPUC has indicated that it expects to issue a proposed decision on May 21, 2021 and a final decision on June 24, 2021.~~

~~The Utility is unable to predict the outcome of this proceeding.~~

~~100~~

LEGISLATIVE AND REGULATORY INITIATIVES

~~Senate~~Assembly Bill ~~350~~180

On June 30, ~~2020,~~2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation.

Assembly Bill 205

On June 30, 2022, the Governor of California signed AB 205, which included authorization for additional incremental CAPP funding of $958 million for California IOUs. The Utility received approximately $200 million in November 2022 to reduce the amounts owed by customer accounts in arrears. The amount of funding was determined by the California ~~governor~~Department of Community Services and Development, which is the agency responsible for administering the CAPP.

Senate Bill846

On September 2, 2022, the Governor of California signed ~~into law~~ SB ~~350 (the Golden State Energy Act), a bill~~846, which ~~authorizes~~supports the ~~creation by~~extension of operations at Diablo Canyon through no later than 2030, with the ~~governor~~potential for an earlier retirement date. For more information, see “Extension of a new entity “Golden State Energy,” a nonprofit public benefit corporation, for the purpose of acquiring the Utility’s assets and serving electric and gas in the Utility’s service territory only in the event that the CPUC determines that the Utility’s Certificate of Public Convenience and Necessity should be revoked pursuant to any process or procedures adopted by the CPUC in its decision approving PG&E Corporation’s and the Utility’s Plan of Reorganization.Diablo Canyon Operations” above.

Senate Bill ~~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 CHT. 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.

~~Assembly Bill 1054~~884

On ~~July 12, 2019,~~September 30, 2022, the Governor of California ~~governor~~ signed ~~into law AB 1054, a bill~~SB 884, which ~~provides for the establishment~~authorizes and expedites OEIS and CPUC review of a ~~statewide fund that will be available~~10-year undergrounding plan. Under SB 884, large electrical corporations may submit 10-year plans for ~~eligible electric utility companies~~undergrounding distribution infrastructure in Tier 2 or 3 HFTDs or rebuild areas to ~~pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by~~OEIS. The plan must include an evaluation of project costs, projected economic benefits over the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. 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 year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293life of the ~~Public Utilities Code, added by AB 1054.~~assets, and any cost-containment assumptions, including the economies of scale necessary to reduce wildfire risk and mitigation costs and establish a sustainable supply chain. OEIS will have up to nine months to review and approve or deny the plan, and then the CPUC will have up to nine months to review and approve or deny the plan, including its costs.

AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.) AB 1054 contemplates that such capital expenditures may be securitized through a customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to a principal amount of approximately $1.19 billion related to fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021.

Inflation Reduction Act

~~Each~~On August 16, 2022, the President of ~~California’s large IOUs~~the United States signed the Inflation Reduction Act. The Inflation Reduction Act includes a 15% corporate alternative minimum tax (“CAMT”) on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for renewable and clean energy sources. Many aspects of the Inflation Reduction Act, including the CAMT, remain uncertain and the U.S. Department of the Treasury and the Internal Revenue Service have ~~elected~~been granted broad authority to ~~participate in~~enact regulations implementing its provisions. Depending on the ~~Wildfire Fund. On July 1, 2020, having satisfied the conditions for~~guidance issued, PG&E Corporation and the Utility’s ~~participation in the Wildfire Fund,~~federal income tax liability could increase substantially. PG&E Corporation and the Utility ~~deposited approximately $5 billion in~~continue to evaluate the ~~Wildfire Fund, which represents PG&E’s initial~~impact of the law and ~~first annual contributions. On December 30, 2020, the Utility made~~ its ~~second annual contribution of $193 million to the Wildfire Fund.~~potential implications.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous ~~wastes;~~substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. ~~(See~~See Item 1A. Risk Factors, “Environmental Regulation” in Item 1. and “Environmental Remediation Contingencies” in Note 1516 of the Notes to the Consolidated Financial Statements in Item 8.)

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit. The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes.

~~101~~

Commodity Price Risk

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices ~~will~~do not affect earnings. Such fluctuations, however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility’s current authorized revenue requirement for natural gas transportation and storage service to non-core customers is not balancing account protected. The Utility recovers these costs in its ~~gas transmission and storage rate cases~~GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately ~~$14~~$3 million and $9$5 million at December 31, ~~2020~~2022 and ~~2019,~~2021, respectively. ~~(See~~See Note 1011 of the Notes to the Consolidated Financial Statements in Item 8.8 for further discussion of price risk management activities.)

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, ~~2020~~2022 and ~~2019,~~2021, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be ~~$89~~$54 million and ~~$45~~$76 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. ~~(See~~See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.8 for further discussion of interest rates.)

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas and related services, then the Utility may find it necessary to procure electricity or gas at current market prices or seek alternate services, which may be higher than the contract prices.

The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility executes many energy contracts under master commodity enabling agreements that may require security. Security may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Security or performance assurance may be required from the Utility or counterparties when current net ~~receivables/~~receivables or payables and exposure exceed contractually specified limits.

The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties:

(in millions)
Exposure (1)
Number of
Wholesale
Customers or
Counterparties
>10% Net Credit
Exposure to
Wholesale
Customers or
Counterparties
>10%
December 31, 2020 $ 250 2 $ 57
December 31, 2019 (2)
$ 381 3 $ 36


	Exposure (1) (in millions)		Number of Wholesale Customers or Counterparties >10%	Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions)
December 31, 2022	$	814	1	$	162
December 31, 2021	$	570	1	$	63

(1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.

~~(2)~~ ~~Exposure balance has been updated to show the maximum positive exposure, including excess collateral postings, instead of the net credit exposure disclosed in prior periods.~~

~~102~~

CRITICAL ACCOUNTING ~~POLICIES~~ESTIMATES

The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting ~~policies~~estimates due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting ~~policies~~estimates and their key characteristics are outlined below.

Contributions to the Wildfire Fund

The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. The 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 area 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 ~~Effective~~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. The other large electric IOUs made their initial contributions to the Wildfire Fund in September 2019. On December 30, ~~2020,~~2021 and 2022, the Utility made its ~~second~~third and fourth annual ~~contribution~~contributions of $193 million each to the Wildfire Fund. As of December 31, ~~2020,~~2022, PG&E Corporation and the Utility have ~~eight~~six remaining annual contributions of $193 ~~million.~~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~~by capitalizing an asset, amortizing to periods ratably based on an estimated period of ~~coverage. The Wildfire Fund is available to pay~~coverage, and incrementally adjusting for ~~eligible claims arising~~accelerated amortization as the level of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the 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. The Wildfire Fund is additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any 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.~~declines, as further described below.

As of December 31, ~~2020,~~2022, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, ~~$1.3 billion~~$935 million in Other non-current liabilities, ~~$464~~$460 million in current assets - Wildfire ~~fund~~Fund asset, and ~~$5.8~~$4.8 billion in non-current assets - Wildfire ~~fund~~Fund asset in the Consolidated Balance Sheets. ~~As of~~During the years ended December 31, ~~2020,~~2022 and 2021, the Utility recorded amortization and accretion expense of ~~$413 million.~~$477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and ~~if applicable, impairment~~acceleration of the amortization of the asset is reflected in Wildfire ~~fund~~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 USU.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 ~~results in the estimated number and severity~~creates annual distributions of ~~catastrophic~~potential losses due to fires that could ~~occur in California within~~be attributed to the participating electric ~~utilities’ service territories during the term~~utilities. Initial use of ~~the Wildfire Fund. Starting with a 5-year period~~five years of historical data, with average annual statewide claims or settlements of approximately $6.5 billion ~~compared to~~versus 12 years of historical data, with average annual statewide claims or settlements of approximately $2.9 billion, ~~for the 12-year historical data,~~ would have ~~decreased the~~resulted in a six year amortization ~~period to 6 years. Similarly,~~period. As of December 31, 2022, a ~~10%~~5% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period ~~to 17~~by five years assuming greater effectiveness and would decrease the amortization period ~~to 12~~by four years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by ~~other~~participating 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~~participating electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

~~103~~

PG&E Corporation and the Utility evaluate all assumptions quarterly orand 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 ~~will~~ assess the Wildfire Fund asset for ~~impairment~~acceleration of the amortization of the asset in the event that a participating ~~utility's~~utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such ~~impairment~~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.~~area. There were fires in the Utility’s and other participating utilities’ ~~service~~services territories ~~in 2020~~since July 12, 2019, including fires for which the cause is ~~currently~~ unknown, ~~and~~ which may in the future be determined to be covered by the Wildfire Fund. AtAs of December 31, ~~2020, there were no such known events requiring a reduction~~2022, PG&E Corporation and the Utility recorded $175 million in Other noncurrent assets for Wildfire Fund receivables related to the 2021 Dixie fire. PG&E Corporation and the Utility recorded $6 million and $43 million of accelerated amortization, reflected in Wildfire Fund expense for the years ended December 31, 2022 and 2021, respectively.

For more information, see “Contributions to the Wildfire Fund ~~asset nor have there been any claims or withdrawals by~~Established Pursuant to AB 1054” in Note 3 and “Wildfire Fund under AB 1054” in Note 15 of the ~~participating utilities against~~Notes to the ~~Wildfire Fund.~~Consolidated Financial Statements in Item 8.

Loss Contingencies

As discussed below, PG&E Corporation and the Utility have recorded material accruals for various wildfire-related, enforcement and legal matters, and environmental remediation liabilities. PG&E Corporation and the Utility have also recorded insurance receivables for third-party claims.

Wildfire-Related Liabilities

PG&E Corporation and the Utility are subject to potential liabilities related to wildfires. PG&E Corporation and the Utility record a wildfire-related liability when ~~it determines~~they determine that a loss is probable and itthey can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

Potential liabilities related to wildfires depend on various factors, including ~~but not limited to~~ negotiations and settlements or the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), 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 extent to which future claims arise, 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 or fines that may be imposed by governmental entities. 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 or the Utility. For example, the Utility’s wildfire-related accruals have changed in the past as new facts and information became available to the Utility, including the availability of new evidence and additional information about the scope and nature of damages.~~(See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)~~

The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including ~~but not limited to~~the factors identified above and estimates based on currently available information and prior experience with wildfires. ~~(See~~See Note 1415 of the Notes to the Consolidated Financial Statements in Item 8.)

Enforcement and Litigation Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss contingency 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, 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. Actual results may differ materially from these estimates and assumptions. ~~(See~~See Note 1415 and ~~“Enforcement~~Note 16 of the Notes to the Consolidated Financial Statements in Item 8.

Loss Recoveries

PG&E Corporation and ~~Litigation Matters”~~the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims. 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 they can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See “Loss Recoveries” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

~~104~~93

Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former ~~manufactured gas plant~~MGP sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has a program related to certain former ~~manufactured gas plant~~MGP sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. 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 is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort.

AtAs of December 31, ~~2020~~2022 and ~~2019,~~2021, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 ~~billion.~~billion each. The Utility’s undiscounted future costs could increase to as much as ~~$2.2~~$2.3 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.

~~Insurance Receivable~~

The Utility has liability insurance from various insurers, which provides coverage for third-party claims. The Utility records insurance recoveries only when a third-party claim is recorded and it is deemed probable that a recovery of that claim will occur and the Utility can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Insurance recoveries are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, discussions with insurers and other information and events pertaining to a particular matter. (See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)

Regulatory Accounting

As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. Despite the ongoing losses related to wildfires ~~(See~~(see Note 1415 of the Notes to the Consolidated Financial Statements in Item ~~8.)~~8), there is no actual or anticipated change in the ~~cost of service~~cost-of-service regulation of the Utility’s operations. Therefore, the Utility continues to apply the accounting ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and Regulated Operations” in Note 3 as well as Note 4 of the Notes to the Consolidated Financial Statements in Item 8. AtAs of December 31, ~~2020,~~2022, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of ~~$11.4~~$20.0 billion and regulatory liabilities (including current regulatory balancing accounts payable) of ~~$12.0~~$20.4 billion.

~~105~~

Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility’s regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. ~~The CPUC has not denied the recovery of any material costs previously recognized by the Utility as regulatory assets for the periods presented.~~ If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition.

A portion of the ~~Utility's~~Utility’s regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account, and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA ~~account tracks~~and RUBA accounts track costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 ~~Pandemic.~~pandemic. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. ~~(For~~For more information, see “Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum ~~Account,”~~Account” and “Regulatory Matters - Catastrophic Event Memorandum Accounts and ~~Applications,” “Regulatory Matters - Wildfire Mitigation Memorandum and Balancing Accounts,” and “Regulatory Matters - COVID-19 Pandemic Protections Memorandum Account.”)~~Applications” above.

Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, 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. The Utility must evaluate the likelihood of recovery in future rates each period. ~~If the criteria are met at a later date,~~In 2022, PG&E Corporation and the Utility ~~would recognize~~recorded a regulatory asset ~~and a related gain in~~associated with SB 901. As of December 31, 2022, the ~~consolidated income statement in the period in which it is determined that the likelihood of recovery is probable.~~SB 901 regulatory asset was approximately $5.4 billion.

In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.

Asset Retirement Obligations

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. ~~(See~~See Notes 3 and 4 of the Notes to the Consolidated Financial Statements in Item 8.)

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation.

At December 31, ~~2020,~~2022, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately ~~$6.4~~$5.9 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.

~~106~~

Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. Adjustments to the pension and other benefit obligation are based on the differences between actuarial assumptions and actual plan results. These amounts are deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP, and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery ~~from customers.~~through rates. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability. ~~(See~~See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)

The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate, and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. ~~(See~~See Note 1213 of the Notes to the Consolidated Financial Statements in Item 8.)

In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for ~~2020~~2023 was ~~6.3%~~6.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in ~~2028~~2031 and beyond.

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the Utility’s defined benefit pension plan, the assumed return of ~~5.1%~~6.1% compares to a ten-year actual return of ~~9.6%~~5.8%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately ~~835~~848 Aa-grade non-callable bonds at December 31, ~~2020.~~2022. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:

(in millions) Increase
(Decrease) in
Assumption
Increase in 2020 Pension
Costs
Increase in Projected
Benefit Obligation at
December 31, 2020
Discount rate (0.50) % $ 77 $ 1,979
Rate of return on plan assets (0.50) % 92 —
Rate of increase in compensation 0.50 % 43 435


(in millions)	Increase (Decrease) in Assumption		Increase in 2022 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2022
Discount rate	(0.50)	%	$	5	$	1,038
Rate of return on plan assets	(0.50)	%	108		—
Rate of increase in compensation	0.50	%	44		207

The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:

(in millions) Increase
(Decrease) in
Assumption
Increase in 2020
Other Postretirement
Benefit Costs
Increase in Accumulated
Benefit Obligation at
December 31, 2020
Health care cost trend rate 0.50 % $ 9 $ 66
Discount rate (0.50) % 11 150
Rate of return on plan assets (0.50) % 13 —

~~107~~


(in millions)	Increase (Decrease) in Assumption		Increase in 2022 Other Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2022
Health care cost trend rate	0.50	%	$	8	$	38
Discount rate	(0.50)	%	11		81
Rate of return on plan assets	(0.50)	%	15		—

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note ~~10:~~11: Derivatives and Note ~~11:~~12: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8.

~~108~~96

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

Year ended December 31,
2020 2019 2018
Operating Revenues
Electric $ 13,858 $ 12,740 $ 12,713
Natural gas 4,611 4,389 4,046
Total operating revenues
18,469 17,129 16,759
Operating Expenses
Cost of electricity 3,116 3,095 3,828
Cost of natural gas 782 734 671
Operating and maintenance 8,684 8,725 7,153
Wildfire-related claims, net of insurance recoveries 251 11,435 11,771
Wildfire fund expense 413 0 0
Depreciation, amortization, and decommissioning 3,468 3,234 3,036
Total operating expenses
16,714 27,223 26,459
Operating Income (Loss) 1,755 (10,094) (9,700)
Interest income 39 82 76
Interest expense (1,260) (934) (929)
Other income, net 483 250 424
Reorganization items, net (1,959) (346) 0
Loss Before Income Taxes (942) (11,042) (10,129)
Income tax provision (benefit) 362 (3,400) (3,292)
Net Loss (1,304) (7,642) (6,837)
Preferred stock dividend requirement of subsidiary 14 14 14
Loss Attributable to Common Shareholders $ (1,318) $ (7,656) $ (6,851)
Weighted Average Common Shares Outstanding, Basic 1,257 528 517
Weighted Average Common Shares Outstanding, Diluted 1,257 528 517
Net Loss Per Common Share, Basic $ (1.05) $ (14.50) $ (13.25)
Net Loss Per Common Share, Diluted $ (1.05) $ (14.50) $ (13.25)


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

See accompanying Notes to the Consolidated Financial Statements.

~~109~~97

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

Year ended December 31,
2020 2019 2018
Net Loss $ (1,304) $ (7,642) $ (6,837)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $7, $0, and $2, at respective dates) (17) (1) 4
Total other comprehensive income (loss) (17) (1) 4
Comprehensive Loss (1,321) (7,643) (6,833)
Preferred stock dividend requirement of subsidiary 14 14 14
Comprehensive Loss Attributable to Common Shareholders $ (1,335) $ (7,657) $ (6,847)


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

See accompanying Notes to the Consolidated Financial Statements.

~~110~~98

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

Balance at December 31,
2020 2019
ASSETS
Current Assets
Cash and cash equivalents $ 484 $ 1,570
Restricted Cash 143 7
Accounts receivable
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates)
(includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of
$143 million and $0 at respective dates)
1,883 1,287
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) 1,083 969
Regulatory balancing accounts 2,001 2,114
Other 1,172 2,617
Regulatory assets 410 315
Inventories
Gas stored underground and fuel oil 95 97
Materials and supplies 533 550
Wildfire fund asset 464 0
Other 1,334 639
Total current assets 9,602 10,165
Property, Plant, and Equipment
Electric 66,982 62,707
Gas 24,135 22,688
Construction work in progress 2,757 2,675
Other 20 20
Total property, plant, and equipment 93,894 88,090
Accumulated depreciation (27,758) (26,455)
Net property, plant, and equipment 66,136 61,635
Other Noncurrent Assets
Regulatory assets 8,978 6,066
Nuclear decommissioning trusts 3,538 3,173
Operating lease right of use asset 1,741 2,286
Wildfire fund asset 5,816 0
Income taxes receivable 67 67
Other 1,978 1,804
Total other noncurrent assets 22,118 13,396
TOTAL ASSETS $ 97,856 $ 85,196


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

See accompanying Notes to the Consolidated Financial Statements.

~~111~~99

PG&E CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

Balance at December 31,
2020 2019
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 3,547 $ 0
Long-term debt, classified as current 28 0
Debtor-in-possession financing, classified as current 0 1,500
Accounts payable
Trade creditors 2,402 1,954
Regulatory balancing accounts 1,245 1,797
Other 580 566
Operating lease liabilities 533 556
Disputed claims and customer refunds 242 0
Interest payable 498 4
Wildfire-related claims 2,250 0
Other 2,256 1,254
Total current liabilities 13,581 7,631
Noncurrent Liabilities
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) 37,288 0
Regulatory liabilities 10,424 9,270
Pension and other postretirement benefits 2,444 1,884
Asset retirement obligations 6,412 5,854
Deferred income taxes 1,398 320
Operating lease liabilities 1,208 1,730
Other 3,848 2,573
Total noncurrent liabilities 63,022 21,631
Liabilities Subject to Compromise 0 50,546
Contingencies and Commitments (Notes 14 and 15) 0 0
Equity
Shareholders' Equity
Common stock, 0 par value, authorized 3,600,000,000 and 800,000,000 shares at respective dates; 1,984,678,673 and 529,236,741 shares outstanding at respective dates 30,224 13,038
Reinvested earnings (9,196) (7,892)
Accumulated other comprehensive loss (27) (10)
Total shareholders' equity 21,001 5,136
Noncontrolling Interest - Preferred Stock of Subsidiary 252 252
Total equity 21,253 5,388
TOTAL LIABILITIES AND EQUITY $ 97,856 $ 85,196


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

See accompanying Notes to the Consolidated Financial Statements.

~~112~~100

PG&E CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


		Year ended December 31,							Year ended December 31,
		2020		2019		2018			2022		2021		2020
Cash Flows from Operating Activities	Cash Flows from Operating Activities							Cash Flows from Operating Activities
Net loss		$	(1,304)	$	(7,642)	$	(6,837)
Net income (loss)								Net income (loss)	$	1,814	$	(88)	$	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:	Adjustments to reconcile net income to net cash provided by operating activities:							Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	Depreciation, amortization, and decommissioning	3,468		3,234		3,036		Depreciation, amortization, and decommissioning	3,856		3,403		3,468
Bad Debt Expense								Bad Debt Expense	143		154		150
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(140)		(79)		(129)		Allowance for equity funds used during construction	(184)		(133)		(140)
Deferred income taxes and tax credits, net	Deferred income taxes and tax credits, net	1,097		(2,948)		(2,532)		Deferred income taxes and tax credits, net	(452)		1,783		1,097
Reorganization items, net (Note 2)	Reorganization items, net (Note 2)	1,458		108		0		Reorganization items, net (Note 2)	—		(73)		1,458
Wildfire fund expense	Wildfire fund expense	413		0		0		Wildfire fund expense	477		517		413
Disallowed capital expenditures	Disallowed capital expenditures	17		581		(45)		Disallowed capital expenditures	15		—		17
Other	Other	399		207		332		Other	517		248		249
Effect of changes in operating assets and liabilities:	Effect of changes in operating assets and liabilities:							Effect of changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	(1,182)		(104)		(121)		Accounts receivable	(757)		(589)		(1,182)
Wildfire-related insurance receivable	Wildfire-related insurance receivable	1,564		35		(1,698)		Wildfire-related insurance receivable	453		(723)		1,564
Inventories	Inventories	6		(80)		(73)		Inventories	(246)		(32)		6
Accounts payable	Accounts payable	58		516		409		Accounts payable	627		117		58
Wildfire-related claims	Wildfire-related claims	(16,525)		(114)		13,665		Wildfire-related claims	(810)		472		(16,525)
Income taxes receivable/payable		0		23		(23)

Other current assets and liabilities	Other current assets and liabilities	(1,079)		77		(281)		Other current assets and liabilities	17		244		(1,079)
Regulatory assets, liabilities, and balancing accounts, net	Regulatory assets, liabilities, and balancing accounts, net	(2,451)		(1,417)		(800)		Regulatory assets, liabilities, and balancing accounts, net	(1,131)		(2,266)		(2,451)
Liabilities subject to compromise	Liabilities subject to compromise	413		12,222		0		Liabilities subject to compromise	—		—		413
Contributions to wildfire fund		(5,200)		0		0
Contributions to Wildfire fund								Contributions to Wildfire fund	(193)		(193)		(5,200)
Other noncurrent assets and liabilities	Other noncurrent assets and liabilities	(142)		197		(151)		Other noncurrent assets and liabilities	(425)		(579)		(142)
Net cash provided by (used in) operating activities	Net cash provided by (used in) operating activities	(19,130)		4,816		4,752		Net cash provided by (used in) operating activities	3,721		2,262		(19,130)
Cash Flows from Investing Activities	Cash Flows from Investing Activities							Cash Flows from Investing Activities
Capital expenditures	Capital expenditures	(7,690)		(6,313)		(6,514)		Capital expenditures	(9,584)		(7,689)		(7,690)
Proceeds from sale of the SFGO								Proceeds from sale of the SFGO	—		749		—
Proceeds from sales and maturities of nuclear decommissioning trust investments	Proceeds from sales and maturities of nuclear decommissioning trust investments	1,518		956		1,412		Proceeds from sales and maturities of nuclear decommissioning trust investments	3,316		1,678		1,518
Purchases of nuclear decommissioning trust investments	Purchases of nuclear decommissioning trust investments	(1,590)		(1,032)		(1,485)		Purchases of nuclear decommissioning trust investments	(3,208)		(1,702)		(1,590)
Proceeds from sales and maturities of customer credit trust investments								Proceeds from sales and maturities of customer credit trust investments	250		—		—
Purchases of customer credit trust investments								Purchases of customer credit trust investments	(1,022)		—		—
Other	Other	14		11		23		Other	34		59		14
Net cash used in investing activities	Net cash used in investing activities	(7,748)		(6,378)		(6,564)		Net cash used in investing activities	(10,214)		(6,905)		(7,748)
Cash Flows from Financing Activities	Cash Flows from Financing Activities							Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	Proceeds from debtor-in-possession credit facility	500		1,850		0		Proceeds from debtor-in-possession credit facility	—		—		500
Repayments of debtor-in-possession credit facility	Repayments of debtor-in-possession credit facility	(2,000)		(350)		0		Repayments of debtor-in-possession credit facility	—		—		(2,000)
Debtor-in-possession credit facility debt issuance costs	Debtor-in-possession credit facility debt issuance costs	(6)		(113)		0		Debtor-in-possession credit facility debt issuance costs	—		—		(6)
Bridge facility financing fees	Bridge facility financing fees	(73)		0		0		Bridge facility financing fees	—		—		(73)
Repayment of long-term debt		(764)		0		(795)

Borrowings under credit facilities	Borrowings under credit facilities	8,554		0		3,960		Borrowings under credit facilities	10,130		9,730		8,554
Repayments under credit facilities	Repayments under credit facilities	(3,949)		0		(775)		Repayments under credit facilities	(9,750)		(9,976)		(3,949)
Credit facilities financing fees	Credit facilities financing fees	(22)		0		0		Credit facilities financing fees	—		(9)		(22)
Net repayments of commercial paper, net of discount of $0, $0, and $1 at respective dates		0		0		(182)
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates		1,448		0		600
Short-term debt matured		0		0		(750)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $178, $0, and $7 at respective dates		13,497		0		793
Exchanged debt financing fees		(103)		0		0
Common stock issued		7,582		85		200
Equity Units issued		1,304		0		0
Other		(40)		(8)		(20)
Net cash provided by financing activities		25,928		1,464		3,031
Net change in cash, cash equivalents, and restricted cash		(950)		(98)		1,219
Cash, cash equivalents, and restricted cash at January 1		1,577		1,675		456
Cash, cash equivalents, and restricted cash at December 31		$	627	$	1,577	$	1,675
Less: Restricted cash and restricted cash equivalents		(143)		(7)		(7)
Cash and cash equivalents at December 31		$	484	$	1,570	$	1,668

As of February 24, 2021, PG&E Corporation and the Utility are aware of 6 complaints on behalf of approximately 240 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and 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 distribution lines was the cause of 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. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation and the Utility were found to have been negligent.

Loss Recoveries

PG&E Corporation and the Utility have ~~insurance coverage~~recovery mechanisms available for wildfire liabilities including ~~wildfire. Additionally, there are several mechanisms~~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 ~~allow for~~ recovery of ~~costs from customers. Potential for recovery is described below. Failure~~a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to ~~obtain a substantial or full~~seek recovery of ~~costs related~~all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2020 Zogg Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

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


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

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or ~~any conclusion that such recovery is no longer probable~~the other mechanisms described in this section, it could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effectimpact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

~~182~~

Insurance

Insurance Coverage

~~PG&E Corporation and~~In April 2022, the Utility ~~have~~purchased approximately $340 million in wildfire liability insurance coverage for the period from April 1, 2022 to April 1, 2023, at a cost of approximately $263 million. Additionally, the Utility purchased approximately $600 million in wildfire ~~events~~liability insurance in August 2022 for the period from August 1, 2022 to August 1, 2023, at a cost of approximately $516 million. The Utility’s wildfire liability insurance is subject to an ~~amount~~initial self-insured retention of ~~$430~~$60 million.

In April 2022, the Utility purchased approximately $725 million ~~(subject~~in non-wildfire liability coverage for the period from April 1, 2022 to April 1, 2023 at a cost of approximately $154 million. The Utility’s non-wildfire liability insurance is subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million.

~~In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount~~As of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million. At December 31, ~~2020,~~2022, PG&E Corporation and the Utility had prepaid insurance of ~~$536~~$424 million, reflected in Other current assets on the Consolidated Balance Sheets.

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

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in ~~general~~excess liability insurance coverage. ~~An advice letter will be required for additional coverage purchased by~~For more information about the ~~Utility in excess of $1.4 billion in coverage.~~

The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.)RTBA, see Note 4 above.

Insurance Receivable

~~PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur.~~ Through December 31, ~~2020,~~2022, PG&E Corporation and the Utility recorded $430 million, $370 million, $530 million, and $45 million for probable insurance recoveries in connection with the 2019 Kincade fire, ~~and $219 million for probable insurance recoveries in connection with~~ the 2020 Zogg ~~fire. PG&E Corporation and~~fire, the ~~Utility have recovered all of the insurance for the 2015 Butte~~2021 Dixie fire, and the 2018 Camp fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each2022 Mosquito fire, ~~is deemed to be a separate occurrence under the insurance policies.~~respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

167

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


Insurance Receivable (in millions)	2022 Mosquito fire		2021 Dixie fire		2020 Zogg fire		2019 Kincade fire		Total
Balance at December 31, 2021	$	—	$	563	$	270	$	414	$	1,247
Accrued insurance recoveries (1)	45		(33)		33		—		45
Reimbursements	—		—		(185)		(313)		(498)
Balance at December 31, 2022	$	45	$	530	$	118	$	101	$	794

Insurance Receivable (in millions) 2020 Zogg fire 2019 Kincade fire 2018 Camp fire 2017 Northern California wildfires 2015 Butte fire Total
Balance at December 31, 2019 $ 0 $ 0 $ 1,380 $ 808 $ 50 $ 2,238
Accrued insurance recoveries 219 430 0 0 0 649
Reimbursements 0 0 (1,380) (783) (50) (2,213)
Balance at December 31, 2020 $ 219 $ 430 $ 0 $ 25 $ 0 $ 674
(1) For the year ended December 31, 2022, the accrued insurance recoveries decreased for the 2021 Dixie fire with a corresponding increase to the 2020 Zogg fire for $33 million.

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

Regulatory Recovery

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

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

FERC TO rates

The Utility recognizes income and reduces its regulatory liability for potential refund through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2022, the Utility recorded reductions of $115 million and $10 million, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund under AB 1054” below. As of December 31, 2022, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery and the Utility recorded $388 million and $50 million, respectively, as regulatory assets in the WEMA. Cost recovery for incremental insurance premiums is addressed through balancing account mechanisms.

~~183~~168

~~Regulatory Recovery~~Wildfire Fund under AB 1054

On ~~June 21, 2018,~~July 12, 2019, the ~~CPUC issued~~California governor signed into law AB 1054, a ~~decision granting~~bill which provides for the ~~Utility’s request~~establishment of a statewide fund that will be available for eligible electric utility companies to ~~establish a WEMA~~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 ~~track specific incremental wildfire liability costs effective~~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 ~~July 26, 2017. The decision does not grant~~December 31, 2022 reflects an expectation that the ~~Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may~~Coverage Year will be ~~unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain; therefore,~~based on the ~~Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.~~calendar year.

~~In addition, SB 901, signed into law on September 21, 2018, requires~~Electric utility companies that draw from the Wildfire Fund will only be required to reimburse amounts that are determined by the CPUC ~~to establish~~in a ~~CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do~~proceeding for cost recovery not exceed the maximum amount that the Utility can pay without harming ratepayers 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, byapplying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses, subject to a disallowance cap equal to 20% of the IOU’s transmission and distribution equity rate base. For the Utility, the disallowance cap would be approximately $3.0 billion based on its 2022 equity rate base, which is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base and would apply for a three calendar-year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company failed to maintain a valid safety certification. Costs that the CPUC determines to be just and ~~only for~~reasonable in accordance with the ~~2017 Northern California wildfires, any amounts~~prudency standard in ~~excess~~AB 1054 will not be reimbursed to the Wildfire Fund, resulting in a draw-down of the ~~CHT.~~Wildfire Fund.

~~On January 10, 2019,~~Before the ~~CPUC adopted an OIR,~~expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which ~~establishes a process~~the Utility expects to ~~develop criteria and a methodology~~be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to ~~inform determinations of the CHT in future applications under~~ Section ~~451.2(a)~~8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for ~~recovery~~12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On December 13, 2022, OEIS approved the Utility’s 2022 application and issued the Utility’s 2022 safety certification.

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

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the allowed amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

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

For more information see Note 3 above.

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

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

~~On July 8, 2019,~~

169

Based on discussions with certain holders of Wildfire-Related Securities Claims, as well as the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20%terms of the ~~CHT or 5 percent~~FVT D&O Claims Settlement Agreement (as defined below) and the settlement agreements with certain carriers of the ~~total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated~~D&O Insurance policies, PG&E Corporation believes it is probable that it will incur a loss in connection with the ~~CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers~~Wildfire-Related Securities Claims. As of December 31, 2022 and each as ~~part of an application under Section 451.2(b).~~further described below:

~~Pursuant to SB 901 and~~•For the ~~CPUC’s methodology adopted~~Wildfire-Related Securities Claims, based on discussions with the plaintiffs in the ~~CHT OIR, on April 30, 2020,~~consolidated securities action, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for such claims, though actual losses could be greater or less than this estimate.

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

•For the Fire Victim Trust D&O Claims, the parties entered into a settlement agreement (the “FVT D&O Claims Settlement Agreement”) pursuant to which PG&E Corporation, the Utility, filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and ~~accelerate a $592~~certain former director and officer defendants paid $117 million ~~payment due~~ to the Fire Victim ~~Trust.~~Trust from D&O insurance policy proceeds. PG&E Corporation intends to apply the remaining proceeds to the Wildfire-Related Securities Claims.

~~Failure to obtain~~As a ~~substantial or full recovery~~result, PG&E Corporation believes it is probable that it will incur a net loss of ~~costs related to wildfires could have a material effect~~$145 million in connection with these matters. As of December 31, 2022, the net loss is reflected in Other income (expense), net on PG&E Corporation’s Consolidated Statements of Income.

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

Wildfire-Related Derivative Litigation

~~NaN~~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 ~~current~~then-current and former members of the ~~Board~~boards of ~~Directors~~directors and certain ~~current~~then-current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility ~~are~~were named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and ~~are~~ denominated In Re California North Bay Fire Derivative ~~Litigation.~~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 described above 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, as discussed below. On November 12, 2020,~~Cases. PG&E Corporation’s and the ~~Trustee for~~Utility’s rights with respect to PG&E Corporation’s and the ~~Fire Victim Trust filed a motion~~Utility’s claims, if any, directly or indirectly related to ~~intervene to substitute as~~any of the ~~plaintiff~~Fires (as defined in the ~~matter. A case management conference is currently scheduled for March 18, 2021, at which time the court will also hear the motion to intervene.~~

~~184~~

~~On August 3, 2018, a third purported derivative lawsuit, entitled~~ ~~Oklahoma Firefighters Pension~~Plan) against former officers and ~~Retirement System v. Chew, et al. (now captioned~~ ~~Trotter v. PG&E Corp., et al.~~), was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officersdirectors of PG&E Corporation and the ~~Utility.~~Utility were assigned to the Fire Victim Trust under the Plan (the “Fire Victim Trust D&O Claims”). Any such recovery was limited to the extent of any D&O Insurance policy proceeds paid by any insurance carrier on behalf of PG&E Corporation ~~is named as a nominal defendant. The lawsuit alleges claims~~or the Utility for ~~breach~~amounts owed pursuant to their indemnification obligations in connection with such causes of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs.action. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On December 14, 2020,March 8, 2021, the court ~~entered~~granted a stipulation ~~and order~~by the parties to substitute the trustee for the Fire Victim Trust as the plaintiff. ~~A case management conference is currently set for April 15, 2021.~~

~~On October 23, 2018, a fourth purported derivative lawsuit, entitled~~ ~~City of Warren Police and Fire Retirement System v. Chew, et al.~~, was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It named as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and named PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

~~On November 21, 2018, a fifth purported derivative lawsuit, entitled~~ ~~Williams v. Earley, Jr., et al.~~ ~~(now captioned~~ ~~Trotter v. Earley, et al.), was filed in federal court in San Francisco, alleging claims identical to those alleged in the~~ ~~Oklahoma Firefighters Pension and Retirement System v. Chew, et al.~~ lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. On January 7, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

On December 24, 2018, a ~~sixth purported~~separate derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et alal..), 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 ~~current~~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 ~~Fire Victim Trust~~trustee filed an amended complaint ~~alleging 2 causes of~~in the Trotter v. Chew action, asserting two direct claims for breach of fiduciary duty against certain ~~former officers and directors. The first cause~~ of ~~action alleges breaches of fiduciary duty in connection with the 2017 Northern California wildfires,~~PG&E Corporation’s and the ~~second cause of action alleges breaches of fiduciary duty in connection with the 2018 Camp fire.~~Utility’s former directors and officers. Neither PG&E Corporation nor the Utility was a party to the action. On March 30, 2021, the Trotter v. Chew and Trotter v. Williams actions were consolidated. On April 26, 2021, the defendants filed demurrers to the amended complaint, which the court sustained in part and overruled in part on November 8, 2021. On November 18, 2021, the trustee filed a second amended complaint. On December 21, 2021, the defendants filed demurrers to the second amended complaint, which the court overruled. On March 10, 2022, the defendants filed motions for summary judgment.

170

On July 26, 2022, PG&E Corporation, the Utility, certain former director and officer defendants, and the Fire Victim Trust entered into the FVT D&O Claims Settlement Agreement, pursuant to which PG&E Corporation, the Utility, ~~are no longer named as nominal defendants. A case management conference is currently set for March 18, 2021.~~and certain former director and officer defendants paid $117 million to the Fire Victim Trust from D&O Insurance policy proceeds, and in return, the Fire Victim Trust released, among other things, any claims related to the assigned claims and the pursuit of the Trotter v. Chew action. Pursuant to the Plan, the settlement was paid solely from the insurance proceeds from the “Side B” D&O Insurance coverage. As a result of the FVT D&O Claims Settlement Agreement, the Trotter v. Chew action was dismissed with prejudice on December 29, 2022.

On January 25, 2019, a ~~seventh~~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 ~~current~~then-current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. ~~A case management conference is currently set for July 7, 2021.~~

~~On January 28, 2019, an eighth purported derivative lawsuit, entitled~~ ~~Blackburn v. Meserve, et al.~~ ~~(now captioned~~ ~~Trotter v. Meserve, et al.), was~~The plaintiff filed ~~in federal court alleging claims for breach of fiduciary duty, unjust enrichment,~~a request to dismiss this action, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. On January 8, 2021,on October 12, 2022, the court ~~entered a stipulation and order to substitute~~dismissed the ~~Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.~~action.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date of the Plan.

~~185~~

The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/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 and/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, 2two purported securities class actions were filed in the ~~United States~~ District Court, ~~for the Northern District of California,~~ naming PG&E Corporation and certain of its ~~current~~then-current and former officers as defendants, entitledDavid C. Weston v. PG&E Corporation, et al.and ~~and~~ Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and ~~transmission line safety in various PG&E Corporation public disclosures.~~other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the ~~federal Securities~~ Exchange Act ~~of 1934~~ 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 ~~the Public Employees Retirement Association of New Mexico (“PERA”)~~PERA as lead plaintiff. ~~The plaintiff~~PERA filed a consolidated amended complaint on November 9, 2018. ~~After the plaintiff requested leave to amend its~~On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the ~~plaintiff filed a second amended consolidated complaint on December 14, 2018.~~PSPS program.

Due to the commencement of the Chapter 11 Cases, ~~PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that~~ the proceedings were automatically stayed as to PG&E Corporation and the Utility pursuant to section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.Utility.

On February 22, 2019, a third purported securities class action was filed in the ~~United States~~ District Court, ~~for the Northern District of California,~~ entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint ~~names~~named as defendants certain ~~current~~then-current and former officers and directors, as well as the underwriters of 4four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility iswas named as a defendant. The complaint ~~alleges~~asserted claims under Section 11 of the Securities Act based on alleged material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. ~~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 ~~currently~~ under submission with the District Court. On September 30, 2022, the District Court issued an order staying the action pending resolution of the bankruptcy proceedings. Accordingly, the District Court administratively closed the case, subject to a motion by the parties thereto to reopen the case. On October 31, 2022, PERA filed a notice of appeal of the District Court’s order staying the action. PERA’s opening brief for the appeal is due March 6, 2023, and the answering brief is due April 5, 2023.

~~186~~171

~~Satisfaction~~Based on discussions with the plaintiffs in this matter, PG&E Corporation believes it is probable that it will incur a loss in connection with this matter. In the second quarter of ~~HoldCo Rescission~~2022, PG&E Corporation recorded a liability in the aggregate amount of $300 million (before available insurance), which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or ~~Damage~~ less than the accrued estimated amount but is unable to reasonably estimate any additional loss because the amount of the liability has not been agreed or otherwise determined, and even if PG&E Corporation were to enter into an agreement with representatives of the plaintiffs in this matter (which would also resolve proofs of claim by these plaintiffs in the bankruptcy), any such agreement would be subject to, among other things, approval by the Bankruptcy Court and the District Court, and class members would have the right to opt out of any such agreement.

Wildfire-Related Securities Claims—Claims ~~and Subordinated Debt Claims~~in the Bankruptcy Court Process

~~Claims against~~ PG&E Corporation and the Utility intend to resolve claims filed in the bankruptcy relating to, among others, the 3three 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 inwith respect ofto 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 any of the Subordinated Claims are ultimately not settled, ~~(with any such resolution being subject to the approval of the Bankruptcy Court),~~ PG&E Corporation and the Utility expect that ~~the~~those Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the ~~Effective~~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 ~~Effective~~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, ~~and/~~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 ~~business,~~ 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,~~such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares ~~issued~~ in ~~respect~~satisfaction of the HoldCo Rescission or Damage Claims ~~were issued~~had occurred on the ~~Effective Date).~~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. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E Corporation and the Utility filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set.

172

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 ~~3, 2020,~~9, 2021, PERA filed a notice of appeal of the District Court’s order to the United States Court of Appeals for the Ninth Circuit and on December 15, 2021, PERA filed its ~~principal brief~~opening brief. On February 14, 2022 and February 17, 2022, the Official Committee of Tort Claimants appointed in ~~support of~~ the ~~appeal. On October 5, 2020,~~Chapter 11 Cases and both PG&E Corporation and the Utility filed their ~~response brief.~~answering briefs, respectively. On May 20, 2022, the Official Committee of Tort Claimants filed a motion to dismiss the case. On June 21, 2022, PERA filed its ~~reply brief on October 26, 2020. No hearing date has been set.~~opposition, and PG&E Corporation and the Utility joined the motion to dismiss. On June 28, 2022, the Official Committee of Tort Claimants filed its reply. On January 13, 2023, PG&E Corporation and the Utility filed a joint motion with PERA requesting the Ninth Circuit Court of Appeals stay and hold PERA’s appeal in abeyance to allow the parties to continue to negotiate a settlement of the matters underlying the appeal. On January 25, 2023, the Ninth Circuit Court of Appeals entered an order granting the joint motion. PERA’s appeal to the Ninth Circuit Court of Appeals remains pending.

~~187~~

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 ~~allow for~~help facilitate the resolution of the ~~outstanding and unresolved~~ Subordinated ~~Claims, which~~Claims. The motion, among other things, ~~requests~~requested approval of ~~certain~~procedures which would allow PG&E Corporation and the Utility to collect trading information ~~request procedures, standard and abbreviated mediation processes, and procedures~~ with respect to the ~~potential filing of~~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~~On January 25, 2021, the Bankruptcy Court granted the Securities Claims Procedures Motion.

On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation and the Utility ~~filed their objection~~have worked to resolve the ~~Renewed 7023 Motion on October 29, 2020. On December 4, 2020,~~Subordinated Claims in accordance with the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, following a timeline setprocedures approved by the Bankruptcy Court, ~~as part~~including by collecting trading information from holders of ~~the oral decision~~Subordinated Claims. Also, pursuant to ~~resolve any outstanding non-substantive objections to PG&E Corporation’s and the Utility’s proposed order granting the Securities Claims Procedures Motion,~~those procedures, PG&E Corporation and the Utility have filed ~~a revised proposed order, which~~numerous omnibus objections in the Bankruptcy Court ~~entered~~to certain of the ~~same day. On January 26, 2021, the~~Subordinated Claims. The Bankruptcy Court has entered ~~a written order denying the Renewed 7023 Motion.~~

~~De-energization 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 current director~~several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain 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 public safety power shutoffs, 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 federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40, 361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action.

~~On May 15, 2020 the officer defendants filed their motion to dismiss in~~ ~~Vataj~~. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter.

On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation,Subordinated Claims subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, includingthese omnibus objections remain pending. 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 relateexpect to ~~(a) allegations that were asserted or could have been asserted in either~~file additional omnibus objections with respect to certain of the ~~complaints in~~ ~~Vataj~~,Subordinated Claims and ~~(b) investments in PG&E Corporation’s stock during~~to continue to act under the ~~relevant period specified in~~procedures approved by the ~~stipulated settlement.~~Bankruptcy Court to resolve the Subordinated Claims.

The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing is currently scheduled for March 11, 2021. The final approval hearing is not yet scheduled. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.

~~188~~

Indemnification Obligations and D&O Insurance Coverage

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations may extend to the claims asserted against ~~the~~certain directors and officers in the securities class ~~action.~~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~~D&O Insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the ~~wildfire-related securities class actions~~litigation matters enumerated above under the headings “Wildfire-Related Securities Class Action” and ~~derivative litigation,~~“Wildfire-Related Derivative Litigation,” and are in ~~communication~~arbitration with ~~the~~certain carriers regarding, among other things, the applicability of ~~the directors and officers insurance~~one year of D&O Insurance policies to those ~~matters.~~ matters (the “Insurance Coverage Claims”).

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

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

Butte County District ~~Attorneys’ Offices Investigations~~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. ~~PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.~~

173

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 (the “People” and the “Butte DA,” respectively)~~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 ~~agreed to plead~~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).

Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire.

Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte District Attorney’s consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022.

On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund.

~~On January 15,~~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, which was established under the Company’s Plan of Reorganization in Bankruptcy~~Trust. The Butte County Superior Court ~~and is managed by a Trustee and a Claims Administrator. The Court~~has since continued the hearing to ~~August 20, 2021 for a further update.~~

Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. For more information see “2019 Kincade Fire” above.

~~The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information.~~

~~189~~

~~Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.~~May 19, 2023.

~~SEC Investigation~~

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation.

~~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. 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 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.

Electric utility companies that draw from the Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.7 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall 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. On July 29, 2020, the Utility submitted its application for a new safety certification. On January 14, 2021, the WSD 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. The 2020 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 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the 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 ratepayers, (ii) $7.5 billion in initial contributions from California’s three IOU companies and (iii) $300 million in annual contributions paid by California’s three IOU companies for at least a 10 year period. The contributions from the IOU companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three IOU companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts 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). 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.

~~190~~

On the Effective Date, having satisfied the conditions for the Utility’s initial participation in the Wildfire Fund, 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. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund.

As of the Effective Date, the Wildfire Fund became available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan.

~~For additional information on the Wildfire Fund, see Note 3 above.~~

NOTE ~~15:~~16: OTHER CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E ~~Corporation’s~~Corporation and the ~~Utility’s policy is to~~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 has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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 (PU Code), Commission General Orders (GO) 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 OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval.

~~191~~

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 settlement agreement stipulates that no violations have been identified in the Tubbs fire. While, as a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates, the Utility has committed not to seek rate recovery for the Tubbs fire except through securitization. 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 has recorded $1.625 billion of the disallowed costs through December 31, 2020.

(in millions)
Description(1)
Expense Capital Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) $ 236 $ 0 $ 236
Transmission Safety Inspections and Repairs Expense (TO)(2)
433 0 433
Vegetation Management Support Costs (FHPMA) 36 0 36
2017 Northern California Wildfires CEMA Expense and Capital (CEMA) 82 66 148
2018 Camp Fire CEMA Expense (CEMA) 435 0 435
2018 Camp Fire CEMA Capital for Restoration (CEMA) 0 253 253
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) 0 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 charged to customers and the amount of disallowance can be reasonably estimated.

~~The Utility expects that the system enhancement spending pursuant to the settlement agreement will 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 (iii) limits the tax savings that must be returned to ratepayers 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. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020.

The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan.

~~As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $152 million primarily in WMPMAas of December 31, 2020 and intends to record the remaining charges of $46 million in 2021.~~

On June 8, 2020, 2 parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, 1 party filed a petition for review of the CPUC decision with the California court of appeals. The Utility is unable to predict the timing and outcome of the petition.

~~192~~

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 ~~TO18, TO19,~~the TO rate case for 2017 (“TO18”), the TO rate case for 2018 (“TO19”), and ~~TO20,~~the TO rate case for 2019 (“TO20”), respectively.

~~On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations.~~ On October 15, 2020, the FERC issued an order that, affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs were filed December 14, 2020 and reply briefs were filed February 12, 2021. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection ofamong 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. ~~Application~~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 ~~operating~~Tax Act on TO18 rates in January and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility filed a request for rehearing of certainFebruary 2018 and (ii) aspects of the rehearing order ~~which was denied by~~other than the Tax Act. The appeals have been consolidated and are being held in abeyance until the FERC addresses the ROE issue on ~~December 17, 2020. The Utility filed~~rehearing.

As a ~~petition for review~~result of an order denying rehearing on the ~~order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties. The ultimate outcome of the items for which~~common plant allocation, the Utility ~~requested rehearing could also impact~~increased its regulatory liabilities for amounts previously collected during the ~~revenues recorded for the~~TO18, TO19, and TO20 ~~periods.~~rate case periods from 2017 through the fourth quarter of 2022 by approximately $416 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility recorded approximately $258 million to Regulatory assets.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in ~~TO18.~~

~~The Utility is unable to predict the timing or outcome of the FERC’s decisions in~~ the TO18 proceeding.

174

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

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

On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liabilities for amounts previously collected during the TO18 and TO19 rate case periods from March 2017 through the first quarter of 2022 by approximately $62.5 million. On April 18, 2022, the Utility and several other parties sought rehearing of the FERC’s determination of the base ROE finding. On May 19, 2022, the FERC denied all parties’ rehearing requests. The Utility has filed an appeal in the D.C. Circuit Court of Appeals, as have the other parties that sought rehearing. The appeal is being held in abeyance until the FERC issues a substantive order on rehearing on the ROE issue.

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

2022 Cost of Capital Application

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

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

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

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

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

175

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 ~~$144~~$69 million and ~~$116~~$77 million atas of December 31, ~~2020~~2022 and December 31, ~~2019,~~2021, respectively. These amounts were included in ~~LSTC at December 31, 2019 and were included in~~ Other current liabilities ~~at December 31, 2020.~~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,~~March 30, 2020, ~~PG&E Corporation and~~ the ~~Utility filed~~Bankruptcy Court granted a motion to dismiss ~~the complaint or in the alternative strike the~~this class action ~~allegations. The motion to dismiss and strike was heard~~ by the ~~Bankruptcy Court on March 10, 2020, and on~~Utility because the plaintiff’s class action claims are preempted as a matter of law by the California Public Utilities Code. On April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to ~~amend, finding that the action was preempted under the California Public Utilities Code.~~amend.

~~193~~

The plaintiff appealed the decision dismissing the complaint to the District Court. On March ~~30, 2020,~~26, 2021, the District Court affirmed the Bankruptcy ~~Court issued an opinion granting the Utility's motion to dismiss~~Court’s dismissal of this ~~class action. The court held that the plaintiff’s class~~ action, ~~claims are preempted as a matter of law by section 1759 of the California Public Utilities Code~~ and thus the plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.”

~~On April 6, 2020,~~ the plaintiff filed a notice of appeal to the Ninth Circuit Court of Appeals. On February 28, 2022, the Ninth Circuit Court of Appeals entered an order certifying two questions of state law to the California Supreme Court. On June 1, 2022, the California Supreme Court accepted certification of the ~~Bankruptcy Court decision dismissing the complaint.~~questions. The plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. The plaintiff filed a designation of the record and statement of the issues on April 20, 2020.

~~On June 8, 2020, the~~ plaintiff filed its opening brief ~~with the District Court. The Utility filed its opposition brief~~ on July ~~6, 2020.~~1, 2022. The Utility’s answering brief was filed on August 31, 2022, and the plaintiff’s reply brief was filed on ~~August 4, 2020 with a request for oral argument. On~~ October 20, ~~2020, the District Court denied the plaintiff’s request for oral argument and stated that if it wants to hear oral argument, it will inform the parties and schedule a hearing.~~

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

~~GT&S Capital Expenditures 2011-2014~~

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures.

On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony and supporting working papers addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.2022.

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

CZU Lightning Complex Fire Notices of Violation

~~Several~~Between November 2020 and January 2021, several governmental entities ~~have~~ raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, ~~alleging violations of Public Resource Code sections related to timber harvest regulations and Forest Practice Rules,~~ the California Coastal Commission, ~~alleging violations of the Coastal Act related to unpermitted development in the coastal zone,~~ the Central Coast Regional Water Quality Control Board, ~~alleging unpermitted discharge to waters,~~ and ~~the~~ Santa Cruz County Board of Supervisors ~~adopting a resolution to file a~~alleging environmental, vegetation management, and unpermitted work violations. In the matter of Santa Cruz County’s complaint with the ~~CPUC. The concerns include potential environmental impacts related to erosion and sedimentation from hazard tree removal and access road use, work in sensitive habitats,~~CPUC, the parties reached a settlement, and the ~~management of wood debris.~~CPUC dismissed the complaint on December 15, 2021. The Utility continues to work with the California Coastal Commission, ~~issued a Notice of Violation letter to the Utility on November 20, 2020,~~Cal Fire, and the Central Coast Regional Water Quality Control Board ~~issued a Notice of Violation letter on December 15, 2020, Cal Fire has issued 5 Notices of Violation through February 8, 2021,~~to resolve any outstanding issues and ~~Santa Cruz County filed a complaint with the CPUC on January 25, 2021. The Utility continues~~ to work with ~~all agencies, as well as~~ Santa Cruz County to ~~resolve any outstanding issues.~~implement the terms of the settlement agreement. Violations can result in penalties, remediation, and other relief.

Based on the information ~~currently~~ available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. ~~The~~Accordingly, PG&E Corporation and the Utility recorded charges during the fourth quarters of 2021 and 2022, each for an amount that is ~~unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties.~~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.~~

~~194~~176

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, 2020 December 31, 2019
Topock natural gas compressor station $ 303 $ 362
Hinkley natural gas compressor station 132 138
Former manufactured gas plant sites owned by the Utility or third parties (1)
659 568
Utility-owned generation facilities (other than fossil fuel-fired),
other facilities, and third-party disposal sites (2)
111 101
Fossil fuel-fired generation facilities and sites (3)
96 106
Total environmental remediation liability $ 1,301 $ 1,275


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

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

(2) Primarily driven by ~~Geothermal~~geothermal landfill and Shell Pond site.

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

The Utility’s gas compressor stations, former ~~manufactured gas plant~~MGP sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous ~~waste laws.~~substances. 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 atas of December 31, ~~2020,~~2022, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. AtAs of December 31, ~~2020,~~2022, the Utility expected to recover ~~$986 million~~$1.05 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

Natural Gas Compressor Station Sites

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

~~195~~177

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 the initial phase of construction was completed in 2021. Additional phases of construction will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as ~~$216~~$240 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the ~~HSM,~~HSMA, where 90% of the costs are recovered inthrough 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 ~~2021.~~2023. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as ~~$138~~$126 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as ~~$460~~$511 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,~~HSMA, where 90% of the costs are recovered inthrough 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 ~~$67~~$51 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the ~~HSM,~~HSMA, where 90% of the costs are recovered inthrough 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~~$50 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s 2two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.

~~196~~178

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~~$2.5 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL ~~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~~one or more terrorist acts occurring within a 12-month period ~~against~~at member sites. NEIL also provides coverage for damages caused by cyber events at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover one or more ~~commercial~~cyber events occurring within a 12-month period at member sites. These coverage amounts are shared by all NEIL members and all nuclear ~~power plants insured~~and non-nuclear property insurance policies issued by NEIL.

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

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately ~~$43~~$41 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately ~~$13.8~~$13.7 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the ~~$13.8~~$13.7 billion of liability protection is provided under a loss-sharing program among ~~utilities owning~~ nuclear ~~reactors.~~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 has experienced 4 outages between July 2020 and February 24, 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 are expected to occur 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. The Utility is working with the vendor that supplied the affected component to understand the root cause and to develop appropriate corrective actions.

If additional shutdowns occur in the future, or if the planned refueling outage is extended due to the inspections and replacement of the affected component, 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.

~~Diablo Canyon carries property damage and outage insurance issued by NEIL. The Utility has notified NEIL of its potential claims for loss recovery.~~

The Utility is unable to reasonably estimate the occurrence or length of future outages, the cost to repair the generator, the loss of power market revenues, or the results of a reasonableness review by the CPUC.

~~197~~

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, ~~2020:~~2022:


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

Power Purchase Agreements
(in millions) Renewable
Energy Conventional
Energy Other Natural
Gas Nuclear
Fuel Total
2021 $ 2,270 $ 582 $ 65 $ 466 $ 64 $ 3,447
2022 2,042 511 62 191 54 2,860
2023 1,997 223 61 158 49 2,488
2024 1,972 72 61 151 47 2,303
2025 1,962 70 61 151 0 2,244
Thereafter 21,335 281 41 184 0 21,841
Total purchase commitments $ 31,578 $ 1,739 $ 351 $ 1,301 $ 214 $ 35,183

179

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, 2020,~~These renewable energy contracts expire at various dates between ~~2021~~2023 and 2043.

Conventional Energy Power Purchase Agreements. The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and ~~resource adequacy~~RA agreements. The Utility’s ~~obligation~~obligations under a portion of these agreements isare contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. ~~As of December 31, 2020, these~~These power purchase agreements expire at various dates between ~~2021~~2023 and ~~2033.~~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, ~~2020,~~2022, QF contracts in operation expire at various dates between ~~2021~~2023 and ~~2049.~~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~~were $2.8 billion in 2022, $3.0 billion in 2021, and $2.9 billion in ~~2020, $3.0 billion in 2019, and $3.1 billion in 2018.~~2020.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the USUnited States Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between ~~2021~~2023 and ~~2026.~~2041. In addition, the Utility has contracted for natural gas storage services in ~~northern~~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~~were $2.4 billion in 2022, $1.2 billion in 2021, and $0.8 billion in ~~2020, $0.9 billion in 2019, and $0.6 billion in 2018.~~2020.

~~198~~

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between ~~2021~~2023 and 2024 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

Payments for nuclear fuel ~~amounted to~~were $44 million in 2022, $79 million in 2021, and $111 million in ~~2020, $74 million in 2019, and $73 million in 2018.~~2020.

180

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 ~~2021~~2023 and ~~2052.~~2057. At December 31, ~~2020,~~2022, the future minimum payments related to these commitments were as follows:

(in millions) Other Commitments
2021 $ 40
2022 30
2023 46
2024 65
2025 60
Thereafter 2,924
Total minimum lease payments $ 3,165


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

Payments for other commitments ~~amounted to~~were $63 million in 2022, $50 million in 2021, and $45 million in ~~2020, $48 million in 2019, and $43 million in 2018.~~2020. Certain office facility leases contain escalation clauses requiring annual increases in rent. The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index. There are options to extend these leases for one to five years.

One of these commitments is treated as a financing lease. At December 31, 2020 and 2019, net financing leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $7 million and $9 million including accumulated amortization of $11 million and $9 million, respectively. The present value of the future minimum lease payments due under these agreements included $2 million and $2 million in Current Liabilities and $5 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, at December 31, 2020 and 2019, respectively.

~~Oakland Headquarters Lease~~

On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.

Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the Lakeside Building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) and a lease security letter of credit in the amount of $75 million.

The term of the Lease will begin on or about March 1, 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~~commitments in the ~~Lease, including insurance costs, maintenance costs and taxes.~~

~~199~~

~~The Lease requires the Landlord~~table above, pursuant to ~~pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create~~SB 901, a ~~separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold~~shareholder contribution to the ~~Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price~~customer credit trust of ~~$892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023.~~

In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO.

~~At December 31, 2020, the Lease Agreement had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.~~

~~NOTE 16: SUBSEQUENT EVENTS~~

~~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~~$1.0 billion 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.

In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million, subject to customary adjustments. SBA paid the Utility $954 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period, resulting in initial cash proceeds of $945 million. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement.

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 potential additional attachment locations on approximately 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.~~made in 2024.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

~~200~~

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, ~~2020,~~2022, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, ~~2020.~~2022.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, ~~2020,~~2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

~~201~~181

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, ~~2020~~2022 and ~~2019,~~2021, the related consolidated statements of income, comprehensive income, equity and cash flows, for each of the three years in the period ended December 31, ~~2020,~~2022, and the related notes and the schedules listed in the Index at Item 15 (collectively, referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2020~~2022 and ~~2019,~~2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2020,~~2022, in conformity with accounting principles generally accepted in the United States of ~~America.~~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, ~~2020,~~2022, based on criteria established in Internal Control —Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February ~~25, 2021,~~22, 2023, expressed an unqualified opinion on the ~~Company's~~Company’s internal control over financial reporting.

~~Emergence from Chapter 11~~

As discussed in Note 2 to the financial statements, the Company emerged from Chapter 11 on July 1, 2020. Under the plan of reorganization, the Company is required to comply with certain terms and conditions as described in Note 2 to the financial statements.

Basis for Opinion

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

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

Critical Audit Matters

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

~~202~~

Regulation and Regulated Operations—Refer to Notes 3, 4 and 1415 to the financial statements

Critical Audit Matter Description

The Company’s subsidiary, Pacific Gas & Electric Company (the “Utility”), follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public ~~Utility~~Utilities Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. ~~Pacific Gas & Electric Company~~The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for nonregulated entities. ~~Pacific Gas & Electric Company~~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.~~rates and records regulatory liabilities for amounts that are likely to be refunded to customers. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

182

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the ~~high~~significant degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate ~~regulators.~~regulators, as well as likelihood of refunds to customers. This required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and a ~~high~~significant degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or likely refund as a regulatory liability under GAAP and are recorded at the appropriate amount.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators and ~~that the~~ costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount included the following, among others:

•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets; and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.

•We read relevant regulatory orders issued by the CPUC and FERC for the ~~Company~~Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•For regulatory matters in process (e.g., applications for cost recovery), we inspected the ~~Company’s~~Utility’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact the ~~Company’s~~Utility’s future rates, for any evidence that might contradict management’s assertions.

•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount. For regulatory liabilities, we selected samples of regulatory liabilities and evaluated whether the Company met the definition of a refund or a future reduction in rates.

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

~~203~~

~~Common Stock Ownership Restrictions – Deferred Tax Asset Valuation—~~Wildfire-Related Contingencies and Recoveries—Refer to Note ~~6 to the financial statements~~

~~Critical Audit Matter Description~~

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 the Company’s ability to use deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). It is more likely than not that the Company has not undergone an ownership change and the Company’s net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.

We identified the Company’s conclusion and disclosure that it has not undergone an ownership change as a critical audit matter due to the significant judgments made by management to interpret Section 382 of the Internal Revenue Code. This required the application of a high degree of auditor judgment and the need to involve our tax specialists when performing audit procedures to evaluate the Company’s disclosure.

~~How the Critical Audit Matter Was Addressed in the Audit~~

~~Our audit procedures related to the Company’s conclusion and disclosure that an ownership change did not occur included the following procedures, among others:~~

•We tested the effectiveness of controls over the review of the analysis and conclusion related to the Company’s determination of whether a change in ownership occurred and the review of disclosure related to this matter.

•With the assistance of our tax specialists, we evaluated the Company’s analysis of whether a change in ownership occurred, including management’s process for interpreting Section 382 of the Internal Revenue Code, the opinion from the Company’s external tax advisor, and determining the aggregate stock ownership change that occurred in conjunction with the Company’s equity financing transactions.

•~~We tested the key facts in the opinion from the Company’s external tax advisor by comparing them to underlying source information and testing the mathematical accuracy of the calculations.~~

•~~We evaluated whether the disclosure appropriately included management’s conclusion that an ownership change did not occur.~~

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

~~Critical Audit Matter Description~~

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund (“Wildfire Fund”) that will be available for eligible California electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. The Company accounts for the contributions to the Wildfire Fund similar to prepaid insurance with expense being allocated to periods ratably based on the estimated period of coverage. As of December 31, 2020, the Wildfire Fund asset is $6.3 billion and the related amortization and accretion for the year ended December 31, 2020 is $413 million. AB 1054 did not specify a period of coverage; therefore the Company estimated the useful life using a Monte Carlo simulation.

We identified the Company’s accounting and disclosure for contributions made to the Wildfire Fund as a critical audit matter due to the significant judgments made by management to (1) determine its accounting conclusion related to the initial and annual contributions as there is no relevant explicit guidance for accounting for contributions to a statewide fund and thus accounting guidance must be applied analogously and (2) determine the useful life, including the key assumptions related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve professionals in our firm with expertise in insurance accounting and our actuarial specialists when performing audit procedures to evaluate the Company’s accounting and disclosure for contributions to the Wildfire Fund.

~~204~~

~~How the Critical Audit Matter Was Addressed in the Audit~~

Our audit procedures related to the accounting for contributions to the Wildfire Fund, the key assumptions used by management in developing its estimate for the useful life of the Wildfire Fund asset, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, and the disclosure relating to the Wildfire Fund asset included the following, among others:

•We tested the effectiveness of controls over (1) the accounting for contributions to the Wildfire Fund; (2) the Company’s review of the key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data; (3) review of the Monte Carlo simulation methodology used to develop the useful life estimate; and (4) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.

•With the assistance of professionals in our firm having expertise in insurance accounting, we evaluated management’s judgments related to its determination of the accounting for contributions made to the Wildfire Fund.

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

•We evaluated each of management’s key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, by inquiring of management, comparing the assumptions to the relevant source data, which included external publicly available data, including information filed with the Company’s regulator related to wildfire mitigation efforts and information related to historic fire-loss and Company-prepared data. Additionally, we inspected other publicly available information for any evidence that might contradict management’s assertions.

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

~~Wildfire-Related Contingencies—Refer to Note 14~~15 to the financial statements

Critical Audit Matter Description

The Company has recorded provisions for loss contingencies related to the 2019 Kincade fire, ~~and~~ 2020 Zogg fire, 2021 Dixie fire, and 2022 Mosquito fire. The Company has recorded an estimated probable ~~loss~~losses of ~~$900~~$1,025 million, $400 million, $1,175 million, and $100 million, respectively, as of December 31, ~~2020,~~2022, which represents the lower end of the range of reasonably possible losses in connection with each of the fires. The Company has recorded estimated recoveries of wildfire-related contingencies, including $439 million and $175 million, in the Wildfire Expense Memorandum Account (“WEMA”) and Wildfire Fund, respectively, as of December 31, 2022.

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

183

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies, related recoveries, and ~~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 and/or reasonably ~~possible;~~possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss, if any, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.

~~205~~

•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires and whether recoveries are probable, by inquiring of management and the Company’s legal counsel regarding the ~~amounts~~amount of probable ~~and~~and/or reasonably possible losses for each fire and each related recovery, including the potential impact of information gained through investigations into the cause of ~~the~~each fire, information from claimants, ~~and~~communication with insurers, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and external legal counsel for recoveries specific to WEMA, regarding probability of recovery for deferred costs not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery. We evaluated the Company’s conclusions regarding probability of recoverability of WEMA and from the Wildfire Fund, under accounting principles generally accepted in the United States of America.

•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness ~~and~~of the data sources utilized to determine the assumption utilized in management’s estimate.

•We read the legal letters from the Company’s external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

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

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

Critical Audit Matter Description

SB 901, signed into law on September 21, 2018, authorized the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the customer harm threshold (CHT) as defined in SB 901. The CPUC authorized the Utility to establish a customer credit trust funded by the Company’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The Company’s subsidiary, PG&E Wildfire Recovery Funding LLC, securitized $7.5 billion of 2017 wildfire claims costs through the issuance of recovery bonds that is designed to be rate-neutral to its customers. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust. The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

184

Also pursuant to the CHT decision, the Utility recorded a SB 901 securitization regulatory asset in the amount of $5.5 billion, reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a SB 901 securitization regulatory liability which represents certain shareholder tax benefits the Utility has recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization expense reflected within Operating and maintenance expense in the Consolidated Statements of Income. At December 31, 2022, the Utility had SB 901 securitization regulatory assets of $5.5 billion and SB 901 securitization regulatory liabilities of $6.1 billion, with SB 901 securitization charges, net recorded on the Consolidated Statement of Income of $608 million.

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

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

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

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

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

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

Critical Audit Matter Description

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. The Company accounts for the contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines. As of December 31, 2022, the Wildfire Fund asset is $5.3 billion and the related amortization and accretion for the year ended December 31, 2022 is $477 million. AB 1054 did not specify a period of coverage; therefore the Company estimated the useful life of 15 years using a Monte Carlo simulation.

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

185

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

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

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February ~~25, 2021~~22, 2023

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

~~206~~186

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"~~“Utility”) as of December 31, ~~2020~~2022 and ~~2019,~~2021, the related consolidated statements of income, comprehensive income, ~~shareholders'~~shareholders’ equity and cash flows, for each of the three years in the period ended December 31, ~~2020,~~2022, and the related notes and the schedules listed in the Index at Item 15 (collectively, referred to as the ~~"financial statements"~~“financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Utility as of December 31, ~~2020~~2022 and ~~2019,~~2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2020,~~2022, in conformity with accounting principles generally accepted in the United States of ~~America.~~America (GAAP).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the ~~Utility's~~Utility’s internal control over financial reporting as of December 31, ~~2020,~~2022, based on criteria established in Internal Control —Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February ~~25, 2021~~22, 2023, expressed an unqualified opinion on the ~~Utility's~~Utility’s internal control over financial reporting.

~~Emergence from Chapter 11~~

As discussed in Note 2 to the financial statements, the Utility emerged from Chapter 11 on July 1, 2020. Under the plan of reorganization, the Utility is required to comply with certain terms and conditions as described in Note 2 to the financial statements.

Basis for Opinion

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

Critical Audit Matters

~~207~~

Regulation and Regulated Operations—Refer to Notes 3, 4, and 1415 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 ~~Utility~~Utilities Commission (the “CPUC”) or the Federal Energy Regulatory Commission (the “FERC”) based on its cost of providing service. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future ~~rates.~~rates and records regulatory liabilities for amounts that are likely to be refunded to customers. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

187

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;~~assets and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC or FERC decision for tracking purposes meet the definition of a regulatory asset or regulatory liability and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.

•We read relevant regulatory orders issued by the CPUC and FERC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s and FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•For regulatory matters in process (e.g., applications for cost recovery), we inspected the Utility’s filings with the CPUC and FERC and the filings with the CPUC and FERC by intervenors that may impact the Utility’s future rates, for any evidence that might contradict management’s assertions.

•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount. For regulatory liabilities, we selected samples of regulatory liabilities and evaluated whether the Utility met the definition of a refund or a future reduction in rates.

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

Wildfire-Related Contingencies and Recoveries—Refer to Note 15 to the financial statements

Critical Audit Matter Description

The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire, 2020 Zogg fire, 2021 Dixie fire and 2022 Mosquito fire. The Utility has recorded estimated probable losses of $1,025 million,$400 million, $1,175 million, and $100 million, respectively as of December 31, 2022, which represents the lower end of the range of reasonably possible losses in connection with each of the fires. The Utility has recorded estimated recoveries of wildfire‐related contingencies, including $439 million and $175 million, in the Wildfire Expense Memorandum Account (“WEMA”) and Wildfire Fund, respectively, as of December 31, 2022.

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

~~208~~

188

~~Common Stock Ownership Restrictions – Deferred Tax Asset Valuation—~~

How the Critical Audit Matter Was Addressed in the Audit

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

•We tested the effectiveness of controls over (1) the Utility’s determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss, if any, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.

•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires and whether recoveries are probable, by inquiring of management and the Utility’s legal counsel regarding the amount of probable and/or reasonably possible losses for each fire and each related recovery, including the potential impact of information gained through investigations into the cause of each fire, information from claimants, communication with insurers, the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and external legal counsel for recoveries specific to WEMA, regarding probability of recovery for deferred costs not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery. We evaluated the Utility’s conclusions regarding probability of recoverability of WEMA and from the Wildfire Fund, under accounting principles generally accepted in the United States of America..

•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness of the data sources utilized to determine the assumption utilized in management’s estimate.

•We read the legal letters from the Utility’s external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

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

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

Critical Audit Matter Description

~~Under Section 382~~SB 901, signed into law on September 21, 2018, authorized the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the ~~Internal Revenue Code, if~~customer harm threshold (CHT) as defined in SB 901. The CPUC authorized the Utility to establish 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~~customer credit trust funded by the Utility’s ~~ability~~shareholders that will provide a monthly credit to ~~use deferred~~customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The Utility’s subsidiary, PG&E Wildfire Recovery Funding LLC, securitized $7.5 billion of 2017 wildfire claims costs through the issuance of recovery bonds that is designed to be rate-neutral to its customers. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust. The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022.

189

Also pursuant to the CHT decision, the Utility recorded a SB 901 securitization regulatory asset in the amount of $5.5 billion, reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a SB 901 securitization regulatory liability which represents certain shareholder tax ~~assets~~benefits the Utility has recognized that will be returned to ~~offset taxable income). In general, an ownership change occurs if~~customers. As the ~~aggregate stock ownership~~Fire Victim Trust sells the remaining shares it holds of ~~certain shareholders increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). It is more likely than not that~~ PG&E Corporation ~~has not undergone an ownership change~~common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the ~~Utility’s net operating loss carryforwards and other tax attributes are not limited by Section 382~~life of the ~~Internal Revenue Code.~~recovery bonds, with such amortization expense reflected within Operating and maintenance expense in the Consolidated Statements of Income. At December 31, 2022, the Utility had SB 901 securitization regulatory assets of $5.5 billion and SB 901 securitization regulatory liabilities of $6.1 billion, with SB 901 securitization charges, net recorded on the Consolidated Statement of Income of $608 million.

We identified the ~~conclusion and disclosure that PG&E Corporation has not undergone an ownership change~~accounting for the SB 901 securitization as a critical audit matter due to the significant judgments made by management ~~to interpret Section 382 of the Internal Revenue Code. This required~~in the application of ~~a high degree~~the relevant GAAP. This required specialized knowledge of ~~auditor judgment and the need to involve our tax specialists~~accounting for rate regulation required significant audit effort when performing audit procedures to evaluate the ~~Utility’s disclosure.~~accounting treatment associated with the transaction.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the ~~conclusion and disclosure that an ownership change did not occur~~application of accounting guidance for the SB 901 securitization included the ~~following procedures, among others:~~following:

•We tested the effectiveness of controls over the ~~review~~evaluation of the ~~analysis~~accounting treatment for the SB 901 securitization and ~~conclusion~~disclosures related to the ~~determination of whether a change in ownership occurred and the review of disclosure related to this matter.~~securitization.

•With the assistance of professionals in our ~~tax specialists,~~firm having expertise in accounting for rate regulation, we evaluated the ~~analysis of whether a change in ownership occurred, including management’s process for interpreting Section 382 of~~conclusions regarding the ~~Internal Revenue Code,~~regulatory asset, regulatory liability, expense and tax accounting treatment applied to the ~~opinion from~~SB 901 securitization by performing the ~~external tax advisor, and determining the aggregate stock ownership change that occurred in conjunction with PG&E Corporation’s equity financing transactions.~~following:

•◦~~We tested~~Read the ~~key facts~~terms and conditions included in the ~~opinion from~~financing order, as well as correspondence with the ~~external tax advisor by comparing them to underlying source information and testing~~CPUC regarding the ~~mathematical accuracy~~intent of the ~~calculations.~~securitization.

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

•We evaluated whether the ~~disclosure appropriately included management’s conclusion that an ownership change did not occur.~~Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.

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

Critical Audit Matter Description

On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund ~~(“Wildfire Fund”)~~ that will be available for eligible ~~California~~ electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019, that are caused by the applicable electric utility company’s equipment. The Utility accounts for the contributions to the Wildfire Fund ~~similar to prepaid insurance with expense being allocated~~by capitalizing an asset, amortizing to periods ratably based on ~~the~~an estimated period of ~~coverage.~~coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines. As of December 31, ~~2020,~~2022, the Wildfire Fund asset is ~~$6.3~~$5.3 billion and the related amortization and accretion for the year ended December 31, ~~2020~~2022 is ~~$413~~$477 million. AB 1054 did not specify a period of coverage; therefore, the Utility estimated the useful life of 15 years using a Monte Carlo simulation.

We identified the Utility’s accounting ~~and disclosure~~ for ~~contributions made to~~ the Wildfire Fund asset as a critical audit matter due to ~~the~~ significant judgments made by management to (1) determine its accounting conclusion related to the initial and annual contributions as there is no relevant explicit guidance for accounting for contributions to a statewide fund and thus accounting guidance must be applied analogously and (2) determine the useful life, ~~including~~specifically the ~~key assumptions~~updated assumption related to the effectiveness of wildfire mitigation ~~efforts and the period of historic fire-loss data.~~efforts. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve ~~professionals in our firm with expertise in insurance accounting and our~~ actuarial specialists when performing audit procedures to evaluate the Utility’s accounting and disclosure ~~for contributions~~related to the Wildfire Fund.

~~209~~190

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the ~~accounting for contributions to the~~ Wildfire Fund the key assumptions used by management in developing its estimate for the useful life of the Wildfire Fund asset, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, and the disclosure relating to the Wildfire Fund asset included the ~~following, among others:~~following:

•We tested the effectiveness of controls over (1) the ~~accounting for contributions to the Wildfire Fund; (2) the~~ Utility’s review of the key assumptions to the useful life estimate, ~~including those~~specifically the update assumption related to the effectiveness of wildfire mitigation efforts, ~~and the period of historic fire-loss data; (3)~~(2) review of the Monte Carlo simulation methodology used to develop ~~the~~ useful life ~~estimate;~~estimate and ~~(4)~~(3) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, ~~including those~~specifically the update assumption related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.

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

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

~~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 and 2020 Zogg fire. The Utility has recorded an estimated probable loss of $900 million as of December 31, 2020, 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 and/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 impact the valuation of the liability; and (3) the disclosures related to the wildfires.

•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires 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, and the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.

~~210~~

•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 and 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.~~

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February ~~25, 2021~~22, 2023

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

~~211~~191

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, ~~2020,~~2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2020,~~2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, ~~2020,~~2022, of the Company and our report dated February ~~25, 2021,~~22, 2023, expressed an unqualified opinion on those ~~consolidated~~ financial ~~statements and included an emphasis of a matter paragraph regarding the Company’s emergence from Chapter 11.~~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 ~~25, 2021~~22, 2023

~~212~~192

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, ~~2020,~~2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2020,~~2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, ~~2020,~~2022, of the Utility and our report dated February ~~25, 2021,~~22, 2023, expressed an unqualified opinion on those ~~consolidated~~ financial ~~statements and included an emphasis of a matter paragraph regarding the Utility’s emergence from Chapter 11.~~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 ~~25, 2021~~22, 2023

~~213~~193

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCE DISCLOSURE

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 31, ~~2020,~~2022, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the 1934 Act is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting

Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management’s report, together with the report of the independent registered public accounting firm, appears in Item 8 of this ~~2020~~2022 Form 10-K under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”

Registered Public Accounting Firm’s Report on Internal Control over Financial Reporting

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, ~~2020~~2022 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

~~214~~194

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding executive officers of PG&E Corporation and the Utility is set forth under “Information About Our Executive Officers” at the end of Part I of this ~~2020~~2022 Form 10-K. Other information ~~regarding directors~~required by this Item 10 will be included in the Joint Proxy Statement relating to the 2023 Annual Meetings of Shareholders under the ~~heading~~headings “Election of Directors of PG&E Corporation and Pacific Gas and Electric Company” in(under the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference. Information regarding compliance with Section 16 of the Exchange Act will be included under the headingsubheadings “Nominees,” “Committee Responsibilities,” “Committee Membership Requirements,” and “Section 16(a) Beneficial Ownership Reporting ~~Compliance” in~~Compliance,”) and “User Guide” (under the ~~Joint Proxy Statement relating to the 2021~~subheading “2024 Annual Meetings, ~~of Shareholders,~~”) which information is incorporated herein by reference.

Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on the Corporate Governance section of PG&E Corporation’s website (www.pgecorp.com/corp/about-us/corporate-governance.page) and on the Utility’s website (www.pge.com/en_US/about-pge/company-information/company-information.page, under the Corporate Governance ~~tab)~~and the Compliance & Ethics tabs): (1) ~~the~~ PG&E Corporation’s and the Utility’s code of conduct (which meets the definition of “code of ethics” of Item 406(b) of the SEC Regulation S-K) adopted by PG&E Corporation and the Utility and applicable to their directors and employees, including their respective ~~Chief Executive Officer and Presidents, as the case may be, Chief Financial Officers, Controllers~~principal executive officers, principal financial officers, controllers, and other executive officers, (2) PG&E Corporation’s and the Utility’s respective corporate governance guidelines, and (3) key Board committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation ~~Nominating~~Sustainability and Governance Committee and the People and Compensation Committee.

If any amendments are made to, or any waivers are granted with respect to, provisions of the ~~code~~“code of ~~conduct adopted~~ethics” by PG&E Corporation ~~and~~or the Utility and that apply to ~~their~~its respective ~~Chief Executive Officer and Presidents, as the case may be, Chief Financial Officers,~~principal executive officers, principal financial officers, or ~~Controllers,~~controllers, PG&E Corporation ~~and~~or the Utility, as appropriate, will post the amended code of ethics ~~on their websites~~ and ~~will disclose~~ any waivers ~~to the code of conduct in a Current Report on Form 8-K.~~

at
www.pgecorp.com/corp/about-us/compliance-ethics/program.page.

~~Procedures for Shareholder Recommendations of Nominees to the Boards of Directors~~

There were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2019 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.

~~Audit Committees and Audit Committee Financial Expert~~

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial experts” as defined by the SEC will be included under the headings “Board Committees and Memberships – Audit Committees” and “Board Committees and Memberships” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information responding to Item 11, for each of PG&E Corporation and the Utility, will be included under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - ~~2020,~~2022,” “Grants of Plan-Based Awards ~~-2020,~~in 2022,” “Outstanding Equity Awards at Fiscal Year End - ~~2020,~~2022,” “Option Exercises and Stock Vested ~~- 2020,~~during 2022,” “Pension Benefits - ~~2020,~~2022,” “Non-Qualified Deferred Compensation - ~~2020,~~2022,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or ~~Disability” and~~Disability,” “Compensation of Non-Employee Directors, ~~– Director Compensation~~” and “Principal Executive Officers’ (PEO) Pay Ratio - ~~2020”~~2022,” in the Joint Proxy Statement relating to the ~~2021~~2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility is set forth under the headings “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the ~~2021~~2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

~~215~~

195

Equity Compensation Plan Information~~(1)~~

The following table provides information as of December 31, ~~2020~~2022 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E ~~Corporation's~~Corporation’s existing equity compensation plans.

(a) (b) (c)
Plan Category
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by shareholders 20,902,525 (2) $ 40.07 (3) 29,174,205 (4)
Equity compensation plans not approved by shareholders — — —
Total equity compensation plans 20,902,525 (2) $ 40.07 (3) 29,174,205 (4)


	(a)		(b)			(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by shareholders	37,654,078	(1)	$	40.04	(2)	53,350,101	(3)
Equity compensation plans not approved by shareholders	—		—			—
Total equity compensation plans	37,654,078	(1)	$	40.04	(2)	53,350,101	(3)

(1)~~Subject to Compensation Committee certification~~

~~(2)~~ Includes 160 phantom stock units, ~~904,067~~9,658,300 restricted stock units and ~~17,724,603~~19,313,387 performance shares. The weighted average exercise price reported in column (b) does not take these awards into account. For performance shares, amounts reflected in this table assume payout in shares at 200% of target or, for performance shares granted in ~~2018,~~2021, reflects the estimated payout percentage of zero percent for performance shares using a total shareholder return and financial metric, 200% for performance shares using ~~a safety metric, and zero percent for performance shares using a financial metric.~~operational metrics. The actual number of shares issued can range from zero percent to 200% of target depending on achievement of performance objectives. For performance-based stock options, amounts reflected in this table reflect actual payout of 102%. Restricted stock units and performance shares are generally settled in net shares. Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, taxes will be paid on behalf of employees. Shares not issued due to share withholding or performance achievement below maximum will be available again for issuance.

~~(3)~~(2) This is the weighted average exercise price for the ~~2,273,695~~2,195,834 options outstanding as of December 31, ~~2020.~~2022.

~~(4)~~(3) Represents the total number of shares available for issuance under all PG&E Corporation’s equity compensation plans as of December 31, ~~2020.~~2022. Stock-based awards granted under these plans include restricted stock units, performance shares, stock options, and phantom stock units. The PG&E Corporation 2014 LTIP, which became effective on May 12, 2014, ~~authorizes~~authorized up to 17 million shares to be issued pursuant to awards granted under the LTIP. In addition, 5.5 million shares related to awards outstanding under the 2006 ~~long-term incentive plan~~LTIP at December 31, 2013, or awards granted under the PG&E Corporation 2006 ~~long-term incentive plan~~LTIP from January 1, 2014, through May 11, 2014, were cancelled, forfeited or expired and became available for issuance under the LTIP. A further 30 million shares were authorized for issuance under the PG&E Corporation 2014 LTIP on July 1, 2020, as part of the Plan. Lastly, an additional 44 million shares were authorized for issuance under the PG&E ~~Corporation’s Chapter 11 Plan of Reorganization~~Corporation 2021 LTIP on June 1, 2021.

For more information, see Note 67 of the Notes to the Consolidated Financial Statements in Item 8.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information responding to Item 13, for each of PG&E Corporation and the Utility, will be included under the headings “Related Party ~~Transactions”~~Transactions,” “Independence,” and ~~“Director Diversity and Independence” and “Board Committees~~“Committees and Memberships” in the Joint Proxy Statement relating to the ~~2021~~2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information responding to Item 14, for each of PG&E Corporation and the Utility, will be included under the heading “Information Regarding the Independent Auditor for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the ~~2021~~2023 Annual Meetings of Shareholders, which information is incorporated herein by reference.

~~216~~196

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a. The following documents are filed as a part of this report:

1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are filed as part of this report in Item 8:

Consolidated Statements of Income for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Comprehensive Income for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Balance Sheets at December 31, ~~2020~~2022 and ~~2019~~2021 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~2020 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~2020 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~2020 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Management’s Report on Internal Controls.

Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

2.The following financial statement schedules are filed as part of this report:

Condensed Financial Information of ~~Parent~~PG&E Corporation (“Parent”) as of December 31, ~~2020~~2022 and ~~2019~~2021 and for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018.~~2020.

Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018.~~2020.

3.Exhibits required by Item 601 of Regulation S-K


Exhibit Number						Exhibit Description
~~2.1~~						~~Confirmation Order, dated June 20, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 20, 2020 (File No. 1-12609), Exhibit 2.1)~~

3.1						Conformed Version of Amended and Restated Articles of Incorporation of PG&E Corporation, ~~effective as of May 29, 2002,~~filed June 22, 2020, as amended by the Certificate of Amendment ~~dated June 22, 2020 (incorporated by reference to~~of Articles of Incorporation of PG&E ~~Corporation’s Form 8 K dated June 20, 2020 (File No. 1-12609) Exhibit 3.1)~~Corporation, filed May 24, 2022

3.2						Bylaws of PG&E Corporation, Amended and Restated as of June 22, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 20, 2020 (File No. 1-12609), Exhibit 3.3)

3.3						Amended and Restated Articles of Incorporation of Pacific Gas and Electric Company, effective as of June 22, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 20, 2020 (File No. 1-2348), Exhibit 3.2)

3.4						Bylaws of Pacific Gas and Electric Company, Amended and Restated as of ~~June 22, 2020~~May 20, 2021 (incorporated by reference into Pacific Gas and Electric Company’s Form 8-K dated ~~June~~May 20, ~~2020~~2021 (File No. 1-2348), Exhibit ~~3.4)~~3.1)

~~217~~

4.1

Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.1)

197


4.2						First Supplemental Indenture, dated as of August 6, 2018, relating to the issuance by Pacific Gas and Electric Company of $500,000,000 aggregate principal amount of 4.25% Senior Notes due August 1, 2023 and $300,000,000 aggregate principal amount of 4.65% Senior Notes due August 1, 2028 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.2)

4.3						Second Supplemental Indenture, dated as of July 1, 2020, to the Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 2, 2020 (File No. 1-2348), Exhibit 4.5)

4.4						Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2005 (File No. 1-2348), Exhibit 4.1)

4.5						First Supplemental Indenture, dated as of March 13, 2007, relating to the issuance of $700,000,000 principal amount of Pacific Gas and Electric Company’s 5.80% Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)

4.6						Third Supplemental Indenture, dated as of March 3, 2008, relating to the issuance of $400,000,000 of Pacific Gas and Electric Company’s 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)

4.7						Sixth Supplemental Indenture, dated as of March 6, 2009, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)

4.8						Eighth Supplemental Indenture, dated as of November 18, 2009, relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)

4.9						Ninth Supplemental Indenture, dated as of April 1, 2010, relating to the issuance of $250,000,000 aggregate principal amount of its 5.80% Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

4.10						~~Tenth~~Ninth Supplemental Indenture, dated as of ~~September 15, 2010,~~June 3, 2021, relating to the ~~issuance of $550,000,000~~$800,000,000 aggregate principal amount of 3.000% First Mortgage Bonds due June 15, 2028 (the “First Mortgage Bonds”), between Pacific Gas and Electric ~~Company’s 3.50% Senior Notes due October 1, 2020~~Company and the Trustee (including the form of First Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated ~~September 15, 2010~~June 1, 2021 (File No. 1-2348), Exhibit 4.1)

4.11						Twelfth Supplemental Indenture, dated as of November 18, 2010, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of its 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)

4.12						Thirteenth Supplemental Indenture, dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)

4.13						Fourteenth Supplemental Indenture, dated as of September 12, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)

4.14						Sixteenth Supplemental Indenture, dated as of December 1, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)

~~218~~198


4.15						Seventeenth Supplemental Indenture, dated as of April 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)

4.16						Eighteenth Supplemental Indenture, dated as of August 16, 2012, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of its 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)

4.17						Nineteenth Supplemental Indenture, dated as of June 14, 2013, relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)

4.18						Twentieth Supplemental Indenture, dated as of November 12, 2013, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)

4.19						Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No. 1-2348), Exhibit 4.1)

4.20						Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 1-2348), Exhibit 4.1)

4.21						Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 1-2348), Exhibit 4.1)

4.22						Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)

4.23						Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015, relating to the issuance of $200,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $450,000,000 aggregate principal amount of its 4.25% Senior Notes due March 15, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 5, 2015 (File No. 1-2348), Exhibit 4.1)

4.24						Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of $600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.95% Senior Notes due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 1, 2016 (File No. 1-2348), Exhibit 4.1)

4.25						Twenty-Eighth Supplemental Indenture, dated as of December 1, 2016, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 30, 2017 and $400,000,000 aggregate principal amount of its 4.00% Senior Notes due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2016 (File No. 1-2348), Exhibit 4.1)

4.26						Twenty-Ninth Supplemental Indenture, dated as of March 10, 2017, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.30% Senior Notes due March 15, 2027 and $200,000,000 aggregate principal amount of its 4.00% Senior Notes due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 10, 2017 (File No. 1-2348), Exhibit 4.1)

~~219~~199


4.27						Thirtieth Supplemental Indenture, dated as of July 1, 2020, to the Amended and Restated Indenture, dated as of April 22, 2005, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior ~~Notes)~~Notes as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.3)

4.28						Indenture, dated as of November 29, 2017, relating to the issuance of $500,000,000 aggregate principal amount of by Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 28, 2018, $1,150,000,000 aggregate principal amount of its 3.30% Senior Notes due December 1, 2027 and $850,000,000 aggregate principal amount of its 3.95% Senior Notes due December 1, 2047 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 29, 2017 (File No. 1-2348), Exhibit 4.1)

4.29						First Supplemental Indenture, dated as of July 1, 2020, to the Indenture, dated as of November 29, 2017, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior ~~Notes)~~Notes as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.4)

4.30						Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National Association (incorporated by reference to PG&E Corporation’s Form S-3 dated February 11, 2014 (File No. 333-193880), Exhibit 4.1)

~~4.31~~						First Supplemental Indenture, dated as of February 27, 2014, relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 2.40% Senior Notes due March 1, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 27, 2014 (File No. 1-12609), Exhibit 4.1)

~~4.32~~						Registration Rights Agreement, dated as of August 6, 2018, among Pacific Gas and Electric Company, Goldman Sachs & Co. LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc., as representatives of the initial purchasers (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 4.5)

~~4.33~~						Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.1)

~~4.34~~4.31						First Supplemental Indenture, dated as of June 19, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the 1.75% First Mortgage Bonds due June 16, 2022, 2.10% First Mortgage Bonds due August 1, 2027, 2.50% First Mortgage Bonds due February 1, 2031, 3.30% First Mortgage Bonds due August 1, 2040 and 3.50% First Mortgage Bonds due August 1, 2050, between Pacific Gas and Electric Company and ~~the Trustee~~The Bank of New York Mellon Trust Company, N.A. (including the form of Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.2)

~~4.35~~						Indenture, dated as of June 23, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 4.1)

~~4.36~~4.32						Second Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Senior Notes Collateral ~~Bonds)~~Bonds as defined therein) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.6)

~~4.37~~						First Supplemental Indenture, dated as of June 23, 2020, relating to the Notes among PG&E Corporation, the Trustee and JP Morgan Chase Bank N.A., as collateral agent (including the form of Notes for each series) (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.2)

~~4.38~~						Escrow Deposit and Disbursement Agreement, dated as of June 23, 2020, by and among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., as escrow agent, and the Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.3)

~~4.39~~						Calculation Agency Agreement, dated as June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A, as calculation agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.3)

~~4.40~~						Escrow Deposit and Disbursement Agreement, dated as of June 19, 2020, by and among Pacific Gas and Electric Company, The Bank of New York Mellon Trust Company, N.A., as escrow agent, and the Trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.4)

~~220~~


~~4.41~~4.33						Third Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to 3.75% First Mortgage Bond due July 1, 2028 and 3.45% First Mortgage Bond due July 1, 2025 (collectively, the “Short-Term Exchange Mortgage Bonds”) and 4.95% First Mortgage Bond due July 1, 2050 and 4.55% First Mortgage Bond due July 1, 2030 (collectively, the “Long-Term Exchange Mortgage Bonds”) between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the ~~New~~ Short-Term Exchange Mortgage Bonds and the ~~New~~ Long-Term Exchange Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.1)

~~4.42~~4.34						Fourth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, relating to 3.15% First Mortgage Bond due July 1, 2026 and 4.50% First Mortgage Bond due July 1, 2040 (collectively, the “Funded Debt Mortgage Bonds”) between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Funded Debt ~~Exchange~~Mortgage Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.2)

~~4.43~~4.35						Fifth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the ~~Credit Agreement Collateral Bonds)~~collateral bonds securing the $1,500,000,000 18-month term loan facility and the $1,500,000,000 364-day term loan facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.7)

~~4.44~~4.36						Sixth Supplemental Indenture, dated as of August 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 4.15)

~~4.45~~4.37						Pledge Agreement, dated as of October 5, 2020, ~~by and~~ between Pacific Gas and Electric Company and MUFG Bank, Ltd. (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 4.1)

200


~~4.46(a)~~4.38						Eighth Supplemental Indenture, dated as of March 11, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $1,500,000,000 aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450,000,000 aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031 Bonds and $450,000,000 aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041 Bonds, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A.(including the form of First Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 8, 2021 (File No. 1-2348), Exhibit 4.1)

4.39						Ninth Supplemental Indenture, dated as of June 3, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $800,000,000 aggregate principal amount of 3.000% First Mortgage Bonds due June 15, 2028 (the “2028 Bonds”), between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of 2028 Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 1, 2021 (File No. 1-2348), Exhibit 4.1)

4.40						Tenth Supplemental Indenture, dated as of June 22, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the collateral bonds, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the forms of collateral bonds securing the revolving credit facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 4.1)

4.41						Eleventh Supplemental Indenture, dated as of October 29, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the collateral bond, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the form of collateral bond securing the 18-month term loan facility) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-2348), Exhibit 4.2)

4.42						Twelfth Supplemental Indenture, dated as of November 15, 2021, to the Indenture of Mortgage, dated as of June 19, 2020, relating to the $300,000,000 aggregate principal amount of Floating Rate Mortgage Bonds due November 14, 2022 (the “Floating Rate Mortgage Bonds”) and the $900,000,000 aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 (the “2023 Bonds”), between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (including the forms of Floating Rate Mortgage Bonds and 2023 Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 10, 2021 File No. 1-2348), Exhibit 4.1)

4.43						Thirteenth Supplemental Indenture, dated as of February 18, 2022, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the forms of the Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 16, 2022 (File No. 1-2348), Exhibit 4.1)

4.44						Fourteenth Supplemental Indenture, dated as of April 4, 2022, relating to the collateral bond between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the form of collateral bond) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 4, 2022 (File No. 1-2348), Exhibit 4.1)

4.45						Fifteenth Supplemental Indenture, dated as of April 20, 2022, relating to the collateral bonds between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the forms of collateral bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 4.1)

4.46						Sixteenth Supplemental Indenture, dated as of June 8, 2022, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (including the forms of the Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 6, 2022 (File No. 1-2348), Exhibit 4.1)

4.47						Seventeenth Supplemental Indenture, dated as of October 4, 2022 to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-2348), Exhibit 4.3)

4.48						Eighteenth Supplemental Indenture, dated as of January 6, 2023, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 6, 2023 (File No. 1-2348), Exhibit 4.1)

201


4.49						Indenture, dated as of June 23, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 4.1)

4.50						First Supplemental Indenture, dated as of June 23, 2020, to the Indenture, dated as of June 23, 2020, relating to the 5.000% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and the 5.250% Senior Secured Notes due July 1, 2030 (the “2030 Notes”; together with the 2028 Notes, the “Notes”), among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., and JP Morgan Chase Bank N.A., as collateral agent (including the form of Notes for each series) (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.2)

4.51						Escrow Deposit and Disbursement Agreement, dated as of June 23, 2020, among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., as escrow agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.3)

4.52						Calculation Agency Agreement, dated as June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A, as calculation agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.3)

4.53						Escrow Deposit and Disbursement Agreement, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as escrow agent and as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.4)

4.54						Indenture, dated as of November 12, 2021, between PG&E Recovery Funding LLC and The Bank of New York Melon Trust Company, N.A. (including forms of the Senior Secured Recovery Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-12609), Exhibit 4.1)

4.55						Series Supplement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and The Bank of New York Melon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-12609), Exhibit 4.2)

4.56						Indenture, dated as of November 30, 2022, between PG&E Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A., (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-12609), Exhibit 4.1)

4.57						Series Supplement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-12609), Exhibit 4.2)

4.58						Indenture, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 4.1)

4.59						Series Supplement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 4.2)

4.60						Indenture, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 10, 2022 (File No. 1-2348), Exhibit 4.1)

4.61						Series Supplement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 10, 2022 (File No. 1-2348), Exhibit 4.2)

4.62 (a)						Description of PG&E Corporation’s Securities – Common Stock and Equity ~~Units.~~Units

~~4.46(b)~~4.62 (b)						Description of Pacific Gas and Electric Company’s Securities – Preferred ~~Stock.~~Stock

202

~~10.1~~	Senior Secured Superpriority Debtor-in-Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019, among Pacific Gas and Electric Company, PG&E Corporation, the financial institutions from time to time party thereto, as lenders and issuing lenders, JPMorgan Chase Bank, N.A., as administrative agent, and Citibank, N.A., as collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated February 1, 2019 (File No. 1-12609), Exhibit 10.1)

~~10.2~~10.1		Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank, National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)

~~10.3~~10.2		Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)

~~10.4~~10.3		Term Loan Agreement, dated as of April 16, 2018, ~~by and~~ among PG&E Corporation, the several banks and other financial institutions or entities from time to time parties thereto, Mizuho Bank, Ltd., Royal Bank of Canada and Sumitomo Mitsui Banking Corporation, as joint lead arrangers and joint bookrunners and Mizuho Bank, Ltd., as administrative agent (incorporated by reference to PG&E Corporation’s Form 8-K dated April 16, 2018 (File No. ~~001-12609)~~1-12609), Exhibit 10.1)

~~221~~


~~10.5~~10.4						Term Loan Agreement, dated as of February 23, 2018, ~~by and~~ among Pacific Gas and Electric Company, the several banks and other financial institutions or entities from time to time parties thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank National Association, as joint lead arrangers and joint bookrunners and The Bank of Tokyo-Mitsubishi UFJ, Ltd, as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 23, 2018 (File No. ~~001-02348)~~1-02348), Exhibit 10.1)

~~10.6~~						Purchase Agreement, dated as of August 2, 2018, among Pacific Gas and Electric Company, Goldman Sachs & Co. LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc. as representatives of the initial purchasers listed on Schedules I-A and I-B thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018 (File No. 1-2348), Exhibit 10.1)

~~10.7~~						Purchase Agreement, dated as of November 27, 2017, among Pacific Gas and Electric Company and Barclays Capital Inc., Citigroup Global Markets Inc., J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC, as representatives of the initial purchasers listed on Schedules I-A, I-B and I-C thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 29, 2017 (File No. 1-2348), Exhibit 10.1)

~~10.8~~						Settlement Agreement among the California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K dated December 22, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99)

~~10.9~~						Pacific Gas and Electric Company Commitment Letter dated October 4, 2019 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 11, 2019 (File No. 1-2348), Exhibit 10.1)

~~10.10~~						~~PG&E Corporation Commitment Letter dated October 4, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated October 11, 2019 (File No. 1-12609), Exhibit 10.2)~~

~~10.11~~						Amendment No. 1 to Pacific Gas and Electric Company Commitment Letter dated November 18, 2019 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2019 (File No. 1-2348), Exhibit 10.11)

~~10.12~~						Amendment No. 1 to PG&E Corporation Commitment Letter dated November 18, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.12)

~~10.13~~						Amendment No. 2 to Pacific Gas and Electric Company Commitment Letter dated December 20, 2019 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 20, 2019 (File No. 1-2348), Exhibit 10.3)

~~10.14~~						~~Amendment No. 2 to PG&E Corporation Commitment Letter dated December 20, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated December 20, 2019 (File No. 1-12609), Exhibit 10.2)~~

~~10.15~~						Amendment No. 3 to Pacific Gas and Electric Company Commitment Letter dated January 31, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 31, 2020 (File No. 1-2348), Exhibit 10.3)

~~10.16~~						~~Amendment No. 3 to PG&E Corporation Commitment Letter dated January 31, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated January 31, 2020 (File No. 1-12609), Exhibit 10.2)~~

~~10.17~~						~~Amendment No. 4 to~~ ~~PG&E Corporation~~ ~~Commitment Letter dated February 14, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2019 (File No. 1-2348), Exhibit 10.17)~~

~~10.18~~						~~Amendment No. 4 to~~ ~~Pacific Gas and Electric Company~~ ~~Commitment Letter dated February 14, 2020 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.18)~~

~~10.19~~						Amendment No. 5 to Pacific Gas and Electric Company Commitment Letter dated February 28, 2020 (incorporated by reference to PG&E Corporation’s Form 10-K/A for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.19)

~~10.20~~						Amendment No. 5 to PG&E Corporation Commitment Letter dated February 28, 2020 (incorporated by reference to PG&E Corporation’s Form 10-K/A for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.20)

~~222~~


~~10.21~~	*	~~Form of Chapter 11 Plan Backstop Commitment Letter (incorporated by reference to PG&E Corporation’s Form 8-K dated March 6, 2020 (File No. 1-12609), Exhibit 10.1)~~

~~10.22~~	**	Restructuring Support Agreement dated as of September 22, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company, certain affiliates of American International Group, Inc., Allstate Insurance Company and certain affiliates, BG Group A Creditors, BG Group B Creditors, certain affiliates of Farmers Insurance Exchange, California Insurance Guarantee Association, Hartford Accident & Indemnity Company and certain affiliates, certain affiliates of Liberty Mutual Insurance Company, Nationwide Mutual Insurance Company and certain affiliates, State Farm Mutual Automobile Insurance Company, State Farm County Mutual Insurance Company of Texas, State Farm Fire and Casualty Company, State Farm General Insurance Company, TLFI Investments, LLC (in its capacity as holder of an economic interest in certain Subrogation Claims), The Travelers Indemnity Company and certain of its property and casualty insurance affiliates, and certain affiliates of United Services Automobile Association (incorporated by reference to PG&E Corporation’s Form 8-K dated September 22, 2019 (File No. 1-12609, Exhibit 10.1)

~~10.23~~	**	First Amendment to Restructuring Support Agreement dated as of October 24, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.21)

~~10.24~~	**	Amended and Restated Restructuring Support Agreement dated as of November 1, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company, certain affiliates of American International Group, Inc., BG Group A Creditors, BG Group B Creditors, certain affiliates of Farmers Insurance Exchange, California Insurance Guarantee Association, Hartford Accident & Indemnity Company and certain affiliates, certain affiliates of Liberty Mutual Insurance Company, Nationwide Mutual Insurance Company and certain affiliates, State Farm Mutual Automobile Insurance Company, State Farm County Mutual Insurance Company of Texas, State Farm General Insurance Company, TLFI Investments, LLC (in its capacity as holder of an economic interest in certain Subrogation Claims), The Travelers Indemnity Company and certain of its property and casualty insurance affiliates, and certain affiliates of United Services Automobile Association (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.22)

~~10.25~~	**	First Amendment to Amended and Restated Restructuring Support Agreement, dated as of November 13, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.23)

~~10.26~~	**	Second Amendment to Amended and Restated Restructuring Support Agreement, dated as of November 18, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.24)

~~10.27~~	**	Third Amendment to Amended and Restated Restructuring Support Agreement, dated as of December 6, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.25)

~~10.28~~	**	Fourth Amendment to Amended and Restated Restructuring Support Agreement, dated as of December 10, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.26)

~~10.29~~	**	Fifth Amendment to Amended and Restated Restructuring Support Agreement, dated as of December 16, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.27)

~~10.30~~	**	Sixth Amendment to Amended and Restated Restructuring Support Agreement, dated as of December 18, 2019, among PG&E Corporation and Pacific Gas and Electric Company and the Requisite Consenting Creditors (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.28)

~~223~~


~~10.31~~						Restructuring Support Agreement dated as of December 6, 2019, by and among PG&E Corporation and Pacific Gas and Electric Company, the Official Committee of Tort Claimants, the attorneys and other advisors and agents for holders of Fire Victim Claims that are signatories to the RSA, and certain funds and accounts managed or advised by Abrams Capital Management, LP and certain funds and accounts managed or advised by Knighthead Capital Management, LLC (incorporated by reference to PG&E Corporation’s Form 8-K dated December 6, 2019 (File No. 1-12609), Exhibit 10.1)

~~10.32~~						First Amendment to the Restructuring Support Agreement, dated as of December 16, 2019, by and among PG&E Corporation and Pacific Gas and Electric Company, the Shareholder Proponents and the Requisite Consenting Fire Claimant Professionals (incorporated by reference to PG&E Corporation’s Form 8-K dated December 16, 2019 (File No. 1-12609), Exhibit 10.1)

~~10.33~~						Restructuring Support Agreement dated as of January 22, 2020, by and among PG&E Corporation and Pacific Gas and Electric Company, the holders of senior unsecured debt of Pacific Gas and Electric Company that are signatories to the RSA, and certain funds and accounts managed or advised by Abrams Capital Management, LP and certain funds and accounts managed or advised by Knighthead Capital Management, LLC (incorporated by reference to PG&E Corporation’s Form 8-K dated January 23, 2020 (File No. 1-12609), Exhibit 10.1)

~~10.34~~						Agency Appointment and Assumption Agreement dated as of September 13, 2019, by and among Wilmington Trust, National Association, in its capacity as Successor Agent, PG&E Corporation, as borrower, and the Lenders signatory thereto, constituting the Required Lenders (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2019 (File No. 1-12609), Exhibit 10.6)

~~10.35~~						Plan Support Agreement as to Plan Treatment of Public Entities’ Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company, the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.1)

~~10.36~~						Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Town of Paradise (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.2)

~~10.37~~						Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the County of Butte (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.3)

~~10.38~~						Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Paradise Recreation & Park District (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.4)

~~10.39~~						Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the County of Yuba (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.5)

~~10.40~~						Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Calaveras County Water District (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.6)

~~10.41~~						Settlement Agreement, dated April 22, 2019, by and between PG&E Corporation and BlueMountain Capital Management, LLC (incorporated by reference to PG&E Corporation’s Form 8-K dated April 22, 2019 (File No. 1-12609), Exhibit 10.1)

~~10.42~~						Amendment No. 1 to Settlement Agreement, dated September 3, 2019, by and between PG&E Corporation and BlueMountain Capital Management, LLC (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2019, Exhibit 10.1)

~~224~~


~~10.43~~10.5		Transmission Control Agreement among the California Independent System Operator Corporation (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to ~~PG&E Corporation’s and~~ Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. ~~1-12609 and File No.~~ 1-2348), Exhibit 10.8)

~~10.44~~		~~Plea Agreement and Settlement, dated March 17, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 17, 2020 (File No. 1-12609), Exhibit 10.1)~~

~~10.45~~10.6	~~***~~	Settlement Agreement, dated April 21, 2020, by and among the TCC, PG&E Corporation, Pacific Gas and Electric Company, FEMA, the SBA, the Department of Agriculture, the Department of the Interior, the United States Department of Housing and Urban Development and the General Services Administration (incorporated by reference to PG&E Corporation’s Form 10-Q dated May 1, 2020 (File No. 1-12609), Exhibit 10.7)

~~10.46~~	~~***~~	Settlement Agreement, dated April 21, 2020, by and among the TCC, PG&E Corporation, Pacific Gas and Electric Company, Cal DDS, Cal DTSC, Cal Fire, Cal OES, Cal Parks, CSU, Caltrans and Cal Vet (incorporated by reference to PG&E Corporation’s Form 10-Q dated May 1, 2020 (File No. 1 12609), Exhibit 10.8)

~~10.47~~	~~***~~	Utility RCF Commitment Letter, dated May 26, 2020, by and among Pacific Gas and Electric Company, J.P. Morgan Chase Bank, N.A., and Citibank, N.A., as co-administrative agents, and the commitment party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8 K dated May 26, 2020 (File No. 1-2348), Exhibit 10.1)

~~10.48~~	~~***~~	Utility Term Loan Commitment Letter, dated May 26, 2020, by and among Pacific Gas and Electric Company, J.P. Morgan Chase Bank, N.A., as administrative agent, and the commitment party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 26, 2020 (File No. 1-2348), Exhibit 10.2)

~~10.49~~	~~***~~	Corporation RCF Commitment Letter, dated May 26, 2020, by and among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, and the commitment parties party thereto. (incorporated by reference to PG&E Corporation’s Form 8-K dated May 26, 2020 (File No. 1-12609), Exhibit 10.3)

~~10.50~~	~~****~~	~~Form of Consent Form (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1-12609), Exhibit 10.1)~~

~~10.51~~	~~****~~	~~Schedule Relating to Form of Consent Form (incorporated by reference to PG&E Corporation’s Form 8-K dated June 9, 2020 (File No. 1-12609), Exhibit 10.1)~~

~~10.52~~	~~****~~	Exhibit A to Consent Form– Form of Amended and Restated Chapter 11 Plan Backstop Commitment Letter (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1 12609), Exhibit 10.2)

~~10.53~~	~~****~~	~~Exhibit B to Consent Form – Redeemable Forward Stock Purchase Contract Term Sheet (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1-12609), Exhibit 10.~~3 )

~~10.54~~	~~****~~	Investment Agreement among PG&E Corporation and the Investors listed in Schedule A thereto (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1-12609), Exhibit 10.4)

~~10.55~~	~~***~~	Agreement to Enter Into Lease and Purchase Option, dated June 5, 2020, between Pacific Gas and Electric Company and TMG Bay Area Investments II, LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 5, 2020 (File No. 1-2348), Exhibit 10.1)

~~10.56~~10.7	~~***~~	Office Lease, dated as of October 23, 2020, ~~by and~~ between Pacific Gas and Electric Company and BA2 300 Lakeside LLC (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.12)

~~10.57~~		Underwriting Agreement dated June 16, 2020, by and among Pacific Gas and Electric Company, J.P. Morgan Securities LLC, Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets and Goldman Sachs & Co. LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 1.1)

~~10.58~~		Underwriting Agreement, dated November 12, 2020, by and among Pacific Gas and Electric Company, BofA Securities, Inc., Mizuho Securities USA LLC, MUFG Securities Americas Inc. and Wells Fargo Securities, LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2020 (File No. 1-2348), Exhibit 1.1)

~~225~~


~~10.59~~		Seventh Supplemental Indenture, dated as of November 16, 2020, relating to the Mortgage Bonds, between Pacific Gas and Electric Company and the Trustee (including the form of Mortgage Bond) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 16, 2020 (File No. 1-2348), Exhibit 4.1)

~~10.60~~10.8		Calculation Agency Agreement, dated as of November 16, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A, as calculation agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 16, 2020 (File No. 1-2348), Exhibit 4.2)

~~10.61~~10.9		~~Underwriting Agreement,~~Repricing Amendment, dated ~~June 18, 2020, by and~~as of February 1, 2021, among PG&E Corporation, ~~J.P. Morgan Securities LLC, Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets~~the Consenting Lenders, the New Lenders (each as defined therein) and ~~Goldman Sachs & Co. LLC~~JPMorgan Chase Bank, N.A, as administrative agent (incorporated by reference to PG&E Corporation’s Form ~~8-K dated June 19, 2020 (File No. 1-2609), Exhibit 1.1)~~

~~10.62~~		~~Term Loan Agreement, dated June 23, 2020, by and among Company, J.P. Morgan Chase Bank, N.A., as administrative agent, and~~10-Q for the ~~lenders party thereto (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 10.1)~~

~~10.63~~	~~******~~	~~Form of Forward Stock Purchase Agreement (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 10.1)~~

~~10.64~~		Underwriting Agreement, dated June 25, 2020, by and among PG&E Corporation, Goldman Sachs & Co., LLC and J.P. Morgan Securities, LLC, as representatives of the several underwriters named in Schedule I thereto, in respect of the Common Stock Offering (incorporated by reference to PG&E Corporation’s Form 8-K dated June 25, 2020 (File No. 1-12609), Exhibit 10.1)

~~10.65~~		Underwriting Agreement, dated June 25, 2020, by and among PG&E Corporation, Goldman Sachs & Co., LLC and J.P. Morgan Securities, LLC, as representatives of the several underwriters named in Schedule I thereto, in respect of the Equity Units Offering (incorporated by reference to PG&E Corporation’s Form 8-K dated June 25, 2020quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.2)

~~10.66~~10.10		Underwriting Agreement, dated as of February 16, 2022, among Pacific Gas and Electric Company, BofA Securities, Inc., J.P. Morgan Securities LLC, Goldman Sachs & Co. LLC and Mizuho Securities LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 16, 2022 (File No. 1-2348), Exhibit 1.1)

203


10.11						Underwriting Agreement, dated as of May 3, 2022, among PG&E Wildfire Recovery Funding LLC, Pacific Gas and Electric Company, Citigroup Global Markets Inc., Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC as representatives for the Underwriters party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 3, 2022 (File No. 1-2348), Exhibit 1.1)

10.12						Underwriting Agreement, dated as of June 6, 2022, among Pacific Gas and Electric Company, BMO Capital Markets Corp., BNP Paribas Securities Corp., BofA Securities, Inc., and Credit Suisse Securities (USA) LLC, as representatives of the several underwriters named therein (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 6, 2022 (File No. 1-2348), Exhibit 1.1)

10.13						Underwriting Agreement, dated as of July 13, 2022, among PG&E Wildfire Recovery Funding LLC, Pacific Gas and Electric Company and Citigroup Global Markets Inc., Barclays Capital Inc., and Goldman Sachs & Co. LLC, as representatives of the Underwriters party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 13, 2022 (File No. 1-2348), Exhibit 1.1)

10.14						Underwriting Agreement, dated as of November 18, 2022, among PG&E Recovery Funding LLC, Pacific Gas and Electric Company and Goldman Sachs & Co. LLC, Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the Underwriters party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2022 (File No. 1-2348), Exhibit 1.1)

10.15						Underwriting Agreement, dated as of January 4, 2023, among Pacific Gas and Electric Company, Barclays Capital Inc., Mizuho Securities USA LLC, MUFG Securities Americas Inc. and Wells Fargo Securities LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated January 6, 2023 (File No. 1-2348), Exhibit 1.1)

10.16						Equity Distribution Agreement, dated as of April 30, 2021, among PG&E Corporation, Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and forward sellers, and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (incorporated by reference to PG&E Corporation’s Form 8-K dated April 30, 2021 (File No. 1-12609), Exhibit 1.1)

10.17						Pledge Agreement, dated as of July 1, 2020, ~~by and~~ among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as collateral agent, revolving administrative agent and term administrative agent, The Bank of New York Mellon Trust Company, N.A., and the secured representatives party thereto from time to time (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.8)

~~10.67~~10.18						Purchase Contract and Unit Agreement, dated as of July 1, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and attorney-in-fact for the holders from time to time as provided therein (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.9)

~~10.68~~10.19						Custodial Agreement, dated as of July 1, 2020, between The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as custodian (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.12)

~~10.69~~10.20						~~Tax Benefits Payment~~Registration Rights Agreement, dated ~~July 1, 2020, between PG&E Corporation~~as of August 6, 2018, among Pacific Gas and Electric Company, Goldman Sachs & Co. LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc., as representatives of the ~~Fire Victim Trust~~initial purchasers (incorporated by reference to ~~PG&E Corporation’s~~Pacific Gas and Electric Company’s Form 8-K dated ~~June 30, 2020~~August 6, 2018 (File No. ~~1-12609)~~1-2348), Exhibit ~~10.1)~~4.5)

~~10.70~~10.21						Registration Rights Agreement, dated as of July 1, 2020, between the Fire Victim Trust and PG&E Corporation (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.2)

~~10.71~~10.22						Amended and Restated Registration Rights Agreement, dated as of July 8, 2021, between PG&E Corporation and the PG&E Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated July 8, 2021 (File No. 1-12609), Exhibit 4.1)

10.23						Credit Agreement, dated as of July 1, 2020, among PG&E Corporation, the several lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and JPMorgan Chase Bank, N.A., as collateral agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.3)

204


10.24						Amendment No. 1 to Credit Agreement, dated as of June 22, 2021, among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time, JP Morgan Chase Bank, N.A., as administrative agent and collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 22, 2021 (File No. 1-12609), Exhibit 10.1)

10.25						Amendment No. 2 to Credit Agreement, dated as of October 4, 2022, among PG&E Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.2)

10.26						Term Loan Agreement, dated as of June 23, 2020, among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 10.1)

10.27						Repricing Amendment, dated as of February 1, 2021, among PG&E Corporation, the Consenting Lenders, the New Lenders (each as defined therein) and JPMorgan Chase Bank, N.A, as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.2)

10.28						Credit Agreement, dated as of July 1, 2020, among Pacific Gas and Electric Company, the several lenders from time to time party thereto, JPMorgan Chase Bank, N.A. and Citibank, N.A., as co-administrative agents, and Citibank, N.A., as designated ~~agent. (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020~~agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.4)

10.29						Amendment No. 1 to Credit Agreement, dated as of June 22, 2021, among Pacific Gas and Electric Company, the several banks and other financial institutions or entities party thereto from time to time, JP Morgan Chase Bank, N.A., as co-administrative agents and Citibank, N.A,, as designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 22, 2021 (File No. 1-2348), Exhibit 10.2)

10.30						Amendment No. 2 to Credit Agreement, dated as of October 4, 2022, among Pacific Gas and Electric Company, the lenders party thereto, Citibank, N.A., as administrative agent and Citibank, N.A., as designated agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-2348), Exhibit 10.3)

~~10.72~~10.31						Term Loan Credit Agreement, dated as of July 1, 2020, among Pacific Gas and Electric Company, the several lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No.1-2348), Exhibit 10.4)

~~10.73~~10.32						Amendment No. 1 to Credit Agreement, dated as of ~~July~~October 29, 2021, among Pacific Gas and Electric Company, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.5)

10.33						Amendment No. 2 to Credit Agreement, dated as of December 31, 2021, among Pacific Gas and Electric Company, the Consenting Lenders, the other Lenders (each as defined therein) and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2021 (File No. 1-2348), Exhibit 10.29)

10.34						Amendment No. 3 to Credit Agreement, dated as of February 8, 2022, among Pacific Gas and Electric Company, the Consenting Lenders (each as defined therein) and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2021 (File No. 1-2348), Exhibit 10.30)

10.35						Term Loan Credit Agreement, dated as of April 4, 2022, among Pacific Gas and Electric Company, the several lenders from time to time parties thereto and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 4, 2022 (File No. 1-2348), Exhibit 10.1)

10.36						Term Loan Credit Agreement, dated as of April 20, 2022, among Pacific Gas and Electric Company, the several lenders from time to time parties thereto and Bank of America, N.A., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 10.1)

10.37						Amendment No. 1 ~~2020, by and~~to Term Loan Credit Agreement, dated as of September 23, 2022, among Pacific Gas and Electric Company, the several lenders from time to time party thereto ~~J.P. Morgan Chase~~and Bank ~~N.A. and Citibank,~~of America, N.A., as ~~co-administrative agents, and Citibank, N.A., as designated~~administrative agent ~~(incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.5)~~

~~226~~205


~~10.74~~10.38						Purchase and Sale Agreement, dated as of October 5, 2020, ~~by and~~ between PG&E AR Facility, LLC, as buyer, and Pacific Gas and Electric Company in its capacity as initial Servicer and in its capacity as Originator (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.1)

~~10.75~~10.39						Amendment No. 1 to Purchase and Sale Agreement, dated as of January 14, 2021, ~~by and~~ between PG&E AR Facility, LLC, as buyer, and Pacific Gas and Electric Company in its capacity as initial Servicer and in its capacity as ~~Originator.~~Originator (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.75)

~~10.76~~10.40						Amendment No. 2 to Purchase and Sale Agreement, dated as of March 18, 2022, among PG&E AR Facility, LLC, as buyer, Pacific Gas and Electric Company, as initial servicer and originator, JPMorgan Chase Bank, N.A., as a committed lender and group agent, Jupiter Securitization Company LLC, as a conduit lender, Mizuho Bank, Ltd., as a committed lender and group agent, BNP Paribas, as a committed lender and group agent, Starbird Funding Corporation, as a conduit lender, Victory Receivables Corporation, as a conduit lender, and MUFG Bank, Ltd., as a committed lender, group agent and administrative agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.2)

10.41						Amendment No. 3 to Purchase and Sale Agreement, dated as of April 20, 2022, among PG&E AR Facility, LLC, as buyer, Pacific Gas and Electric Company, as initial Servicer and as an originator, the financial institutions party thereto and listed therein as committed lenders, conduit lenders, and group agents, and MUFG Bank, Ltd., as a Committed Lender, a Group Agent, and MUFG Bank, Ltd., Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 10.3)

10.42						Receivables Financing Agreement, dated as of October 5, 2020, ~~by and~~ among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.2)

~~10.77~~10.43						Amendment No. 1 to Receivables Financing Agreement, dated as of January 14, 2021, ~~by and~~ among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit ~~Parties.~~Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.77)

~~10.78~~10.44						Amendment No. 2 to Receivables Financing Agreement, dated as of February 12, 2021, ~~by and~~ among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit ~~Parties.~~Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.78)

~~10.79~~10.45						Amendment No. 3 to Receivables Financing Agreement, dated as of May 5, 2021, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.2)

10.46						Amendment No. 4 to Receivables Financing Agreement, dated as of September 15, 2021, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (each as defined therein) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2021 (File No. 1-12609), Exhibit 10.3)

10.47						Amendment No. 5 to Receivables Financing Agreement, dated as of March 18, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-2348), Exhibit 10.4)

10.48						Amendment No. 6 to Receivables Financing Agreement, dated as of April 20, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 20, 2022 (File No. 1-2348), Exhibit 10.2)

206



10.49		Amendment No. 7 to Receivables Financing Agreement and Limited Waiver, dated as of June 21, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2022 (File No. 1-2348), Exhibit 10.6)

10.50		Amendment No. 8 to Receivables Financing Agreement, dated as of September 30, 2022, among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its capacity as initial Servicer, the financial institutions from time to time party thereto and listed therein as lenders and MUFG Bank, Ltd., as Administrative Agent (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.7)

10.51		Collection Account Intercreditor Agreement, dated as of October 5, 2020, ~~by and~~ among Pacific Gas and Electric Company, MUFG Bank, Ltd., and each trustee, indenture trustee, lender administrative agent, collateral agent, purchaser or other party described in Exhibit A therein (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.3)

~~10.80~~10.52		~~Master Transaction~~Recovery Property Servicing Agreement, dated as of ~~February 2,~~November 12, 2021, bybetween PG&E Recovery Funding LLC and ~~between~~ Pacific Gas and Electric Company, as Servicer (incorporated by reference to Pacific Gas and ~~Golden State Licensing, LLC.~~Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.1)

~~10.81~~10.53	~~***~~	~~Offer Letter~~Recovery Property Purchase and Sale Agreement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.2)

10.54		Administration Agreement, dated as of November 12, 2021, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as administrator (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2021 (File No. 1-2348), Exhibit 10.3)

10.55		Recovery Property Servicing Agreement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 6, 2022 (File No. 1-2348), Exhibit 10.1)

10.56		Recovery Property Purchase and Sale Agreement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 6, 2022 (File No. 1-2348), Exhibit 10.2)

10.57		Administration Agreement, dated as of May 10, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Administrator (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 6, 2022 (File No. 1-2348), Exhibit 10.3)

10.58		Recovery Property Servicing Agreement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 10.1)

10.59		Recovery Property Purchase and Sale Agreement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 10.2)

10.60		Administration Agreement, dated as of July 20, 2022, between PG&E Wildfire Recovery Funding LLC and Pacific Gas and Electric Company, as Administrator (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 15, 2022 (File No. 1-2348), Exhibit 10.3)

10.61		Recovery Property Servicing Agreement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Servicer, (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-2348), Exhibit 10.1)

10.62		Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Seller (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-2348), Exhibit 10.2)

207


10.63		Administration Agreement, dated as of November 30, 2022, between PG&E Recovery Funding LLC and Pacific Gas and Electric Company, as Administrator(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 30, 2022 (File No. 1-2348), Exhibit 10.3 )

10.64		PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, dated as of July 8, 2021, among PG&E Corporation, Pacific Gas and ~~Patricia K. Poppe, effective November 13, 2020~~Electric Company, PG&E ShareCo LLC and the PG&E Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated ~~November 18, 2020~~July 8, 2021 (File No. 1-12609), Exhibit 10.1)

~~10.82~~10.65	~~***~~	~~Form of Director and Officer Indemnification Agreement (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.8)~~

~~10.83~~	***	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of June 3, 2019 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.9)

~~10.84~~10.66	**	Consent to Recoupment of Excess Performance Share Units award for 2021 under the PG&E Corporation 2014 Long-Term Incentive Plan

10.67	**	Consent to Recoupment of Excess Performance Share Units, dated as of October 14, 2022, between PG&E Corporation and John R. Simon

10.68	**	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective as of ~~June 3, 2019 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2019 (File No. 1-12609), Exhibit 10.10)~~February 15, 2023

~~10.85~~10.69	~~***~~	Performance Share Agreement subject to financial goals between William D. Johnson and PG&E Corporation dated August 14, 2019 for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.43)

~~10.86~~	~~***~~	Performance Share Agreement subject to customer affordability goals between William D. Johnson and PG&E Corporation dated August 14, 2019 for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.44)

~~10.87~~	~~***~~	Performance Share Agreement subject to safety goals between William D. Johnson and PG&E Corporation dated August 14, 2019 for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.45)

~~10.88~~	~~***~~	Restricted Stock Unit Agreement between William D. Johnson and PG&E Corporation for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.46)

~~10.89~~	~~***~~	Offer Letter between Pacific Gas and Electric Company and Andrew M. Vesey dated July 30, 2019 (incorporated by reference to Pacific Gas and Electric’s Form 10-Q for the quarter ended September 30, 2019 (File No. 1-2348), Exhibit 10.7)

~~227~~


~~10.90~~	~~***~~	Performance Share Agreement subject to financial goals between Andrew M. Vesey and PG&E Corporation dated November 12, 2019 for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.49)

~~10.91~~	~~***~~	Performance Share Agreement subject to customer affordability goals between Andrew M. Vesey and PG&E Corporation dated November 12, 2019 for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.50)

~~10.92~~	~~***~~	Performance Share Agreement subject to safety goals between Andrew M. Vesey and PG&E Corporation dated November 12, 2019 for 2019 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.51)

~~10.93~~	~~***~~	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Janet Loduca dated December 3, 2018 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2018 (File No. 1-12609), Exhibit 10.27)

~~10.94~~	***	PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)

~~10.95~~10.70	***	PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective ~~September~~as of February 15, ~~2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.3)~~2023

~~10.96~~10.71	***	~~Description of~~PG&E Corporation Short-Term Incentive Plan, ~~for Officers~~as amended effective as of ~~PG&E Corporation and its subsidiaries, effective January 1, 2020(incorporated by reference to PG&E Corporation’s Form 8-K dated March 4, 2020 (File No. 1-12609))~~February 15, 2023.

~~10.97~~10.72	~~***~~	Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)

~~10.98~~	~~***~~	Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)

~~10.99~~	***	Pacific Gas and Electric Company Officer Relocation Handbook, effective December 15, ~~2019.~~2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.99)

~~10.100~~10.73	~~***~~	~~Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective January 1, 2019.~~

~~10.101~~	~~***~~	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective February 6, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2014 (File No. 1-2348), Exhibit 10.37)

~~10.102~~	***	Postretirement Life Insurance Plan of Pacific Gas and Electric Company, as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)

~~10.103~~10.74	***	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective February 6, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2014 (File No. 1-2348), Exhibit 10.37)

10.75	**	Amendment to the Postretirement Life Insurance Plan of ~~Restricted Stock Unit Agreement~~Pacific Gas and Electric Company, effective February 12, 2016, (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for ~~2018 grants under~~ the ~~PG&E Corporation 2014 Long-Term Incentive~~quarter ended March 31, 2016 (File No. 1-2348), Exhibit 10.4)

10.76	**	Amendment to the Postretirement Life Insurance Plan of Pacific Gas and Electric Company, effective January 1, 2019 (incorporated by reference to PG&E Corporation’s Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~March~~December 31, ~~2018~~2020 (File No. 1-12609), Exhibit ~~10.07)~~10.100)

~~10.104~~10.77	***	~~Form~~Amendment to the Postretirement Life Insurance Plan of Restricted Stock Unit Agreement for 2017 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2017 (File No. 1-12609), Exhibit 10.01)Pacific Gas and Electric Company, effective January 1, 2020

~~10.105~~10.78	***	Form of Stock Option Agreement for 2018 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12609), Exhibit 10.08)

~~10.106~~10.79	~~***~~	Form of Stock Award Agreement for 2019 grants to non-employee directors under the PG&E Corporation 2014 Long-Term Incentive Plan, as amended February 6, 2020 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2019 (File No. 1-12609), Exhibit 10.83)

~~10.107~~	***	Form of Restricted Stock Unit ~~Award~~ Agreement for ~~2020 grants to non-employee directors under the PG&E Corporation 2014 Long-Term Incentive Plan, effective January 1, 2020.~~

~~228~~



~~10.108~~	~~***~~	~~Form of Performance Share Agreement subject to financial goals for 2018~~2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, ~~2018 (File~~2021 File No. 1-12609), Exhibit ~~10.04)~~10.13)

~~10.109~~10.80	**	Form of Restricted Stock Unit Agreement for 2022 grants to Non-Employee Directors under the PG&E Corporation 2021 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2022 (File No. 1-12609), Exhibit 10.11)

10.81	**	Form of Performance Share Unit Agreement subject to customer experience, public safety and financial goals for ~~2018~~2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, ~~2018~~2021 (File No. 1-12609), Exhibit ~~10.05)~~10.14)

208


~~10.110~~10.82	***	Form of Performance Share Unit Agreement subject to total shareholder return goals for ~~2018~~2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, ~~2018~~2021 (File No. 1-12609), Exhibit ~~10.06)~~10.15)

~~10.111~~10.83	***	~~Form of Performance Share Agreement subject to total shareholder return goals for 2017 grants under the~~ PG&E Corporation ~~2014~~2021 Long-Term Incentive Plan, as amended effective as of June 16, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, ~~2017~~2022 (File No. 1-12609), Exhibit ~~10.02)~~10.12)

~~10.112~~10.84	***	Form of ~~Performance Share Agreement subject to safety and financial goals for 2017 grants under the~~ PG&E Corporation ~~2014~~2021 Long-Term Incentive Plan ~~(incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2017 (File No. 1-12609), Exhibit 10.03)~~

~~10.113~~	~~***~~	~~PG&E Corporation 2010 Executive~~Non-Annual Restricted Stock ~~Ownership Guidelines~~Unit Award, as ~~adopted~~amended effective ~~January 1, 2011~~August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, ~~2010~~2022 (File No. 1-12609), Exhibit ~~10.3)~~10.8)

~~10.114~~10.85	**	Form of PG&E Corporation 2021 Long-Term Incentive Plan Restricted Stock Unit Award, as amended effective August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.9)

10.86	**	Form of PG&E Corporation 2021 Long-Term Incentive Plan Performance Share Unit Award, as amended effective August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.10)

10.87	**	Amendment to 2014 PG&E Corporation Long-Term Incentive Plan Award Agreements and 2021 PG&E Corporation Long-Term Incentive Plan Award Agreements, dated as of August 14, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2022 (File No. 1-12609), Exhibit 10.11)

10.88	**	PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)

~~10.115~~10.89	**	PG&E Corporation 2010 Executive Stock Ownership Guidelines, as amended effective as of January 1, 2022 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.14)

10.90	**	PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)

~~10.116~~10.91	***	Amendment to PG&E Corporation Golden Parachute Restriction Policy dated as of December 31, 2008 ~~(amendment to comply with Internal Revenue Code Section 409A Regulations)~~ (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)

~~10.117~~10.92	**	PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No.1-12609), Exhibit 10.24)

10.93	**	Amended and Restated PG&E Corporation Director Grantor Trust Agreement dated as of October 1, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.01)

~~10.118~~10.94	***	Amended and Restated PG&E Corporation Officer Grantor Trust Agreement dated as of October 1, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2015 (File No. 1-12609), Exhibit 10.2)

~~10.119~~10.95	***	PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective February 19, ~~2019.~~2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2020 (File No. 1-12609), Exhibit 10.119)

~~10.120~~10.96	***	Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated as of December 18, 1996 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)

~~10.121~~10.97	***	Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated as of July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)

~~10.122~~10.98	***	~~Restricted Stock Unit Award~~Form of Director and Officer Indemnification Agreement ~~between PG&E Corporation and William L. Smith, dated August 3, 2020~~ (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended ~~September~~June 30, ~~2020~~2019 (File No. 1-12609), Exhibit ~~10.31)~~10.08)

~~10.123~~10.99	***	Non-Annual Restricted Stock Unit Award Agreement between Adam L. Wright and PG&E Corporation, ~~and John Simon,~~ dated ~~August 14, 2020~~as of March 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended ~~September 30, 2020~~March 31, 2021 (File No. ~~1-12609),~~1-12609, Exhibit ~~10.32)~~10.8)

~~10.124~~	~~***~~	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Jason Wells, dated August 14, 2020 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.33)

~~10.125~~	~~***~~	Performance Share Award Agreement between PG&E Corporation and James Welsch, dated March 2, 2020 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.34)

~~229~~209



~~10.126~~10.100	***	~~Performance Share~~Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and ~~Michael Lewis,~~Marlene M. Santos, dated as of March ~~2, 2020(incorporated~~15, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended ~~September 30, 2020~~March 31, 2021 (File No. 1-12609), Exhibit ~~10.35)~~10.10)

~~10.127~~10.101	***	~~Amended and Restated Performance Share~~Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and ~~William L. Smith,~~Christopher A. Foster, dated ~~August 3, 2020~~.as of March 22, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2021 (File No. 1-12609), Exhibit 10.11)

~~10.128~~10.102	***	~~Performance Share~~Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and ~~David Thomason,~~Julius Cox, dated as of March ~~2, 2020~~1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2021 (File No. 1-12609), Exhibit 10.92)

10.103	**	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Carla Peterman, dated as of June 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2021 (File No. 1-12609), Exhibit 10.93)

10.104	**	Consent to Amend Award Agreement, dated as of August 14, 2022, between PG&E Corporation and John R. Simon (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, ~~2020~~2022 (File No. 1-12609), Exhibit ~~10.37)~~10.12)

~~10.129~~10.105	~~***~~	Separation Agreement between Andy Vesey and Pacific Gas and Electric Company dated, September 21, 2020 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.38)

~~10.130~~	~~***~~	Separation Agreement between Pacific Gas and Electric Company and Janet Loduca, dated July 17, 2020 (last amended effective July 23, 2020) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-1260) Exhibit 10.39

~~10.131~~	***	PG&E Corporation 2014 Long-Term Incentive Plan (as adopted effective May 12, 2014 and as last amended effective July 1, 2020) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2020 (File No. 1-12609), Exhibit 10.40)

~~10.132~~10.106	**	PG&E Corporation 2021 Long-Term Incentive Plan (incorporated by reference to Appendix A to PG&E Corporation’s definitive proxy statement on Schedule 14A filed on April 8, 2021)

10.107	**	PG&E Corporation 2012 Officer Severance Policy, as amended effective November 1, 2021 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2022 (File No. 1-12609), Exhibit 10.13)

10.108	**	Form of ~~2020 Performance Share Award~~Restricted Stock Unit Agreement under the PG&E Corporation ~~2014~~2021 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended ~~September 30, 2020~~March 31, 2022 (File No. 1-12609), Exhibit ~~10.41)~~10.10)

~~10.133~~10.109	***	Form of Performance Share Award Agreement under the PG&E Corporation ~~2012 Officer Severance Policy, as amended effective as of September 24, 2020~~2021 Long-Term Incentive (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended ~~September 30, 2020~~March 31, 2022 (File No. 1-12609), Exhibit ~~10.42)~~10.11)

14		Employee Code of Conduct

21		Subsidiaries of the Registrant

23.1		PG&E Corporation Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)

23.2		Pacific Gas and Electric Company Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)

24		Powers of Attorney

31.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	~~*******~~	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1	~~*******~~	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

210



101.PRE						XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF						XBRL Taxonomy Extension Definition Linkbase Document

104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

~~230~~


*						This Form of Chapter 11 Plan Backstop Commitment Letter is substantially similar in all material respects to each Chapter 11 Plan Backstop Commitment Letter that is otherwise required to be filed as an exhibit, except as to the Backstop Party and the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Chapter 11 Plan Backstop Commitment Letter). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Chapter 11 Plan Backstop Commitment Letter, with a schedule identifying the Chapter 11 Plan Backstop Commitment Letters omitted and setting forth the material details in which each Chapter 11 Plan Backstop Commitment Letter differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Chapter 11 Plan Backstop Commitment Letter so omitted.

**						In accordance with Item 601(a)(5) of Regulation S-K, certain schedules or similar attachments to this exhibit have been omitted from this filing. Such omitted schedules or similar attachments include information about the Subrogation Claims held by each Consenting Subrogation Creditor. The registrant agrees to furnish a supplemental copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request.

~~***~~						~~Management contract or compensatory agreement.~~

~~****~~						The Form of Consent Form is substantially identical in all material respects to each Consent Form that is otherwise required to be filed as an exhibit, except as to the Backstop Party, the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Backstop Commitment Letter) and the amount of such Backstop Party’s Forward Contract Purchase Commitment (as defined in the Consent Form). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Consent Form, with a schedule dated as of June 9, 2020 identifying the Consent Forms omitted and setting forth the material details in which each Consent Form differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted.

~~*****~~						In accordance with Item 601(a)(5) of Regulation S-K, certain schedules (or similar attachments) to this exhibit have been omitted from this filing. Such omitted schedules (or similar attachments) include information relating to the Property. The registrants will provide a copy of any omitted schedule to the Securities and Exchange Commission or its staff upon request. In accordance with Item 601(b)(10)(iv) of Regulation S-K, certain provisions or terms of the Lease Agreement attached as an exhibit to the Agreement have been redacted. Such redacted information includes proprietary information about the Property. The registrants will provide an unredacted copy of the exhibit on a supplemental basis to the Securities and Exchange Commission or its staff upon request.

~~**~~						The Form of Forward Stock Purchase Agreement is substantially identical in all material respects to each Forward Stock Purchase Agreement that is otherwise required to be filed as an exhibit, except as to the Purchaser (as defined in the Forward Stock Purchase Agreement), the amount of such Purchaser’s Greenshoe Backstop Purchase Amount and the amount of such Purchaser’s Additional Backstop Premium Shares. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the Purchase Agreements omitted and setting forth the material details in which each Forward Stock Purchase Agreement differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted.Management contract or compensatory plan, contract or arrangement.

~~*******~~						~~Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.~~

~~231~~211

ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, ~~2020~~2022 to be signed on their behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.


	PG&E CORPORATION		PACIFIC GAS AND ELECTRIC COMPANY
	(Registrant)		(Registrant)

	/s/ PATRICIA K. POPPE		/s/ ADAM L. WRIGHT
	Patricia K. Poppe		Adam L. Wright

By:	Chief Executive Officer	By:	Executive Vice President, Operations and Chief Operating Officer

Date:	February ~~25, 2021~~22, 2023	Date:	February ~~25, 2021~~22, 2023

			/s/ MARLENE M. SANTOS
			Marlene M. Santos

		By:	Executive Vice President and Chief Customer Officer

		Date:	February 22, 2023

			/s/ JASON M. GLICKMAN
			Jason M. Glickman

		By:	Executive Vice President, Engineering, Planning, and Strategy

		Date:	February 22, 2023

Signature

Title

Date

A. Principal Executive Officers

/s/ PATRICIA K. POPPE

Chief Executive Officer

February ~~25, 2021~~22, 2023

Patricia K. Poppe

(PG&E Corporation)

/s/ ADAM L. WRIGHT

Executive Vice President, Operations and Chief Operating Officer

February ~~25, 2021~~22, 2023

Adam L. Wright

(Pacific Gas and Electric Company)

212

/s/ MARLENE M. SANTOS

Executive Vice President and Chief Customer Officer

February 22, 2023

Marlene M. Santos

(Pacific Gas and Electric Company)

/s/ JASON M. GLICKMAN

Executive Vice President, Engineering, Planning, and Strategy

February 22, 2023

Jason M. Glickman

(Pacific Gas and Electric Company)

B. Principal Financial Officers

/s/ CHRISTOPHER A. FOSTER

Executive Vice President and ~~Interim~~ Chief Financial Officer

February ~~25, 2021~~22, 2023

Christopher A. Foster

(PG&E Corporation)

/s/ ~~DAVID S. THOMASON~~STEPHANIE N. WILLIAMS

Vice President, Chief Financial Officer, and

February ~~25, 2021~~22, 2023

~~David S. Thomason~~Stephanie N. Williams

Controller (Pacific Gas and Electric Company)

B.C. Principal Accounting Officer

/s/ ~~DAVID S. THOMASON~~STEPHANIE N. WILLIAMS

Vice President, Chief Financial Officer, and

February ~~25, 2021~~22, 2023

~~David S. Thomason~~Stephanie N. Williams

Controller (Pacific Gas and Electric Company)

~~232~~

C. Directors (PG&E Corporation and Pacific Gas and Electric Company, unless otherwise noted)

/s/ RAJAT BAHRI

Director

February ~~25, 2021~~22, 2023

Rajat Bahri

/s/ CHERYL F. CAMPBELL

Director

February ~~25, 2021~~22, 2023

Cheryl F. Campbell

Chair of the Board (Pacific Gas and Electric Company)

/s/ KERRY W. COOPER

Director

February ~~25, 2021~~22, 2023

Kerry W. Cooper

/s/ JESSICA L. DENECOUR

Director

February ~~25, 2021~~22, 2023

Jessica L. Denecour

/s/ MARK E. FERGUSON III

Director

February ~~25, 2021~~22, 2023

Mark E. Ferguson III

/s/ ROBERT C. FLEXON

Director

February ~~25, 2021~~22, 2023

Robert C. Flexon

Chair of the Board (PG&E Corporation)

/s/ W. CRAIG FUGATE

Director

February ~~25, 2021~~22, 2023

W. Craig Fugate

213

/s/ ARNO L. HARRIS

Director

February ~~25, 2021~~22, 2023

Arno L. Harris

/s/ CARLOS M. HERNANNDEZ

Director

February 22, 2023

Carlos M. Hernandez

/s/ MICHAEL R. NIGGLI ~~JR.~~

Director

February ~~25, 2021~~22, 2023

Michael R. Niggli ~~Jr.~~

/s/ PATRICIA K. POPPE

Director

February ~~25, 2021~~22, 2023

Patricia K. Poppe

~~/s/ DEAN L. SEAVERS~~

~~Director~~

~~February 25, 2021~~

~~Dean L. Seavers~~

~~Chair of the Board (Pacific Gas and Electric Company)~~

~~233~~

/s/ WILLIAM L. SMITH

Director

February ~~25, 2021~~22, 2023

William L. Smith

~~/s/ OLUWADARA J. TRESEDER~~

~~Director~~

~~February 25, 2021~~

~~Oluwadara J. Treseder~~

/s/ BENJAMIN F. WILSON

Director

February ~~25, 2021~~22, 2023

Benjamin F. Wilson

/s/ ADAM L. WRIGHT

Director (Pacific Gas and Electric Company)

February ~~25, 2021~~22, 2023

Adam L. Wright

~~/s/ JOHN M. WOOLARD~~

~~Director~~

~~February 25, 2021~~

~~John M. Woolard~~

*By:

/s/ JOHN R. SIMON

February ~~25, 2021~~22, 2023

John R. Simon, Attorney-in-Fact

~~234~~214

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)

CONDENSEDSTATEMENTS OF INCOME AND COMPREHENSIVE INCOME


	Years Ended December 31,
(in millions, except per share amounts)	2022		2021		2020
Administrative service revenue	$	109	$	118	$	127
Operating expenses	(193)		(124)		(103)
Interest income	3		—		—
Interest expense	(261)		(230)		(149)
Other income (expense)	(201)		(54)		13
Reorganization items, net	—		1		(1,649)
Equity in earnings of subsidiaries	2,154		137		411
Income (loss) before income taxes	1,611		(152)		(1,350)
Income tax benefit	(132)		(64)		(46)
Net Income (loss)	$	1,743	$	(88)	$	(1,304)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates)	$	21	$	7	$	(17)
Total other comprehensive income (loss)	21		7		(17)
Comprehensive Income (Loss)	$	1,764	$	(81)	$	(1,321)
Weighted Average Common Shares Outstanding, Basic (1)	2,235		2,463		1,257
Weighted Average Common Shares Outstanding, Diluted (1)	2,380		2,463		1,257
Net earnings (loss) per common share, basic	$	0.78	$	(0.05)	$	(1.05)
Net earnings (loss) per common share, diluted	$	0.73	$	(0.05)	$	(1.05)

(1) Includes 247,743,590 and 477,743,590 shares of common stock issued to ShareCo as of December 31, 2022 and 2021, respectively.

215

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF ~~PARENT~~PG&E CORPORATION (“PARENT”) – (Continued)

CONDENSED BALANCE SHEETS~~STATEMENTS OF INCOME AND COMPREHENSIVE INCOME~~

Years Ended December 31,
(in millions, except per share amounts) 2020 2019 2018
Administrative service revenue $ 127 $ 138 $ 90
Operating expenses (103) (114) (91)
Interest income 0 1 2
Interest expense (149) (21) (15)
Other income (expense) 13 10 (2)
Reorganization items, net (1,649) (26) 0
Equity in earnings of subsidiaries 411 (7,622) (6,832)
Loss before income taxes (1,350) (7,634) (6,848)
Income tax provision (benefit) (46) 8 3
Net loss $ (1,304) $ (7,642) $ (6,851)
Other Comprehensive Income (Loss)
Pension and other postretirement benefit plans obligations (net of taxes of $7, $0, and $2, at respective dates) $ (17) $ (1) $ 4
Total other comprehensive income (loss) (17) (1) 4
Comprehensive Loss $ (1,321) $ (7,643) $ (6,847)
Weighted Average Common Shares Outstanding, Basic 1,257 528 517
Weighted Average Common Shares Outstanding, Diluted 1,257 528 513
Net loss per common share, basic $ (1.05) $ (14.50) $ (13.25)
Net loss per common share, diluted $ (1.05) $ (14.50) $ (13.25)


	Balance at December 31,
(in millions)	2022		2021
ASSETS
Current Assets
Cash and cash equivalents	$	125	$	126
Advances to affiliates	46		21
Income taxes receivable	10		10
Other current assets	12		12
Total current assets	193		169
Noncurrent Assets
Equipment	—		2
Accumulated depreciation	—		(2)
Net equipment	—		—
Investments in subsidiaries	33,021		30,232
Other investments	160		181
Deferred income taxes	423		297
Total noncurrent assets	33,604		30,710
Total Assets	$	33,797	$	30,879
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt, classified as current	27		27
Accounts payable – other	88		200
Other current liabilities	369		69
Total current liabilities	484		296
Noncurrent Liabilities
Long-term debt	4,588		4,592
Other noncurrent liabilities	134		168
Total noncurrent liabilities	4,722		4,760
Common Shareholders’ Equity
Common stock	36,132		35,129
Reinvested earnings	(7,542)		(9,286)
Accumulated other comprehensive income (loss)	1		(20)
Total common shareholders’ equity	28,591		25,823
Total Liabilities and Shareholders’ Equity	$	33,797	$	30,879

~~235~~

~~PG&E CORPORATION~~

~~SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT– (Continued)~~

~~CONDENSED BALANCE SHEETS~~

Balance at December 31,
(in millions) 2020 2019
ASSETS
Current Assets
Cash and cash equivalents $ 223 $ 448
Advances to affiliates 48 120
Income taxes receivable 12 12
Other current assets 13 11
Total current assets 296 591
Noncurrent Assets
Equipment 2 2
Accumulated depreciation (2) (2)
Net equipment 0 0
Investments in subsidiaries 25,244 5,102
Other investments 186 173
Operating lease right of use asset 3 6
Deferred income taxes 237 187
Total noncurrent assets 25,670 5,468
Total Assets $ 25,966 $ 6,059
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt, classified as current 28 0
Accounts payable – other 49 47
Operating lease liabilities 3 3
Other current liabilities 72 3
Total current liabilities 152 53
Noncurrent Liabilities
Debtor-in-possession financing 4,624 0
Operating lease liabilities 0 3
Other noncurrent liabilities 191 58
Total noncurrent liabilities 4,815 61
Liabilities Subject to Compromise 0 810
Common Shareholders’ Equity
Common stock 30,224 13,038
Reinvested earnings (9,198) (7,893)
Accumulated other comprehensive income (loss) (27) (10)
Total common shareholders’ equity 20,999 5,135
Total Liabilities and Shareholders’ Equity $ 25,966 $ 6,059

~~236~~216

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF ~~PARENT~~PG&E CORPORATION (“PARENT”) – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

Year ended December 31,
2020 2019 2018
Cash Flows from Operating Activities:
Net loss $ (1,304) $ (7,642) $ (6,851)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization 28 43 78
Equity in earnings of subsidiaries (412) 7,622 6,833
Deferred income taxes and tax credits-net (50) 0 (62)
Reorganization items, net (Note 2) 1,548 11 0
Current income taxes receivable/payable 0 6 9
Liabilities subject to compromise 12 28 0
Other 97 (62) 41
Net cash provided by (used in) operating activities
(81) 6 48
Cash Flows From Investing Activities:
Investment in subsidiaries (12,986) 0 (45)
Net cash used in investing activities
(12,986) 0 (45)
Cash Flows From Financing Activities:
Debtor-in-possession credit facility debt issuance costs 0 (16) 0
Bridge facility financing fees (40) 0 0
Borrowings under revolving credit facility 0 0 425
Repayments under revolving credit facility 0 0 (125)
Net repayments of commercial paper 0 0 (132)
Short-term debt financing 0 0 350
Proceeds from issuance of long-term debt 4,660 0 0
Repayment of long-term debt (664) 0 (350)
Common stock issued 7,582 85 200
Equity Units issued 1,304 0 0
Net cash provided by financing activities 12,842 69 368
Net change in cash and cash equivalents (225) 75 371
Cash and cash equivalents at January 1 448 373 2
Cash and cash equivalents at December 31 $ 223 $ 448 $ 373
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized $ (105) $ (3) $ (13)
Income taxes, net 0 0 10
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets $ 0 $ 9 $ 0
Common stock issued in satisfaction of liabilities 8,276 0 0


	Year ended December 31,
	2022		2021		2020
Cash Flows from Operating Activities:
Net income (loss)	$	1,743	$	(88)	$	(1,304)
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization	95		51		28
Equity in earnings of subsidiaries	(2,160)		(139)		(412)
Deferred income taxes and tax credits, net	(126)		(60)		(50)
Reorganization items, net (Note 2)	—		(32)		1,548
Current income taxes receivable/payable	—		2		—
Liabilities subject to compromise	—		—		12
Other	339		81		97
Net cash used in operating activities	(109)		(185)		(81)
Cash Flows From Investing Activities:
Investment in subsidiaries	(994)		—		(12,986)
Dividends received from subsidiaries (1)	1,275		—		—
Net cash provided by (used in) investing activities	281		—		(12,986)
Cash Flows From Financing Activities:
Bridge facility financing fees	—		—		(40)



Proceeds from issuance of long-term debt	—		—		4,660
Repayment of long-term debt	(28)		(28)		(664)
Proceeds from (repayments of) intercompany note from the Utility	(145)		145		—
Common stock issued	—		—		7,582
Equity Units issued	—		—		1,304
Other	—		(29)		—
Net cash provided by (used in) financing activities	(173)		88		12,842
Net change in cash and cash equivalents	(1)		(97)		(225)
Cash and cash equivalents at January 1	126		223		448
Cash and cash equivalents at December 31	$	125	$	126	$	223

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(233)	$	(207)	$	(105)
Income taxes, net	—		1		—
Supplemental disclosures of noncash investing and financing activities

Common stock issued in satisfaction of liabilities	—		—		8,276
Changes to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement	(2,337)		4,854		—

(1)

Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock.

~~237~~217

PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~

(in millions) Additions
Description Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2020:
      Allowance for uncollectible accounts (1)
$ 43 $ 138 $ 0 $ 35 $ 146
2019:
      Allowance for uncollectible accounts (1)
$ 56 $ 0 $ 0 $ 13 $ 43
2018:
      Allowance for uncollectible accounts (1)
$ 64 $ 34 $ 0 $ 42 $ 56
2020


(in millions)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

~~238~~218

PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, ~~2020, 2019,~~2022, 2021, and ~~2018~~

(in millions) Additions
Description Balance at Beginning of Period Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2020:
      Allowance for uncollectible accounts (1)
$ 43 $ 138 $ 0 $ 35 $ 146
2019:
      Allowance for uncollectible accounts (1)
$ 56 $ 0 $ 0 $ 13 $ 43
2018:
      Allowance for uncollectible accounts (1)
$ 64 $ 34 $ 0 $ 42 $ 56
2020


(in millions)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
Valuation and qualifying accounts deducted from assets:
2022:
Allowance for uncollectible accounts (1)	$	171	$	146	$	—	$	151	$	166
2021:
Allowance for uncollectible accounts (1)	$	146	$	136	$	—	$	111	$	171
2020:
Allowance for uncollectible accounts (1)	$	43	$	138	$	—	$	35	$	146

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

~~239~~219


(Mark One)
☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the Fiscal Year Ended December 31, ~~2020~~2022

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the transition period from _________ to ___________


Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, no par value	PCG	The New York Stock Exchange
Equity Units	PCGU	The New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, ~~5% series A redeemable~~6% nonredeemable	~~PCG-PE~~PCG-PA	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable	PCG-PB	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemable	PCG-PC	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemable	PCG-PD	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% series A redeemable	PCG-PE	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemable	PCG-PG	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemable	PCG-PH	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable	PCG-PI	NYSE American LLC
~~First preferred stock, cumulative, par value $25 per share, 6% nonredeemable~~	~~PCG-PA~~	~~NYSE American LLC~~
~~First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable~~	~~PCG-PB~~	~~NYSE American LLC~~
~~First preferred stock, cumulative, par value $25 per share, 5% nonredeemable~~	~~PCG-PC~~	~~NYSE American LLC~~


Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, ~~2020,~~2022, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation common stock			~~$12,130~~$20,819 million
Pacific Gas and Electric Company common stock			Wholly owned by PG&E Corporation


UNITS OF MEASUREMENT
GLOSSARY
FORWARD-LOOKING STATEMENTS
PART 1
ITEM 1. BUSINESS
Triple Bottom Line
Regulatory Environment
Environmental Regulation
Ratemaking Mechanisms
Human Capital
Electric Utility Operations
Natural Gas Utility Operations
Competition
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
RESULTS OF OPERATIONS
LIQUIDITY AND FINANCIAL RESOURCES
~~CONTRACTUAL COMMITMENTS~~
~~ENFORCEMENT AND~~ LITIGATION MATTERS
REGULATORY MATTERS
LEGISLATIVE AND REGULATORY INITIATIVES
ENVIRONMENTAL MATTERS
RISK MANAGEMENT ACTIVITIES
CRITICAL ACCOUNTING ~~POLICIES~~ESTIMATES
NEW ACCOUNTING PRONOUNCEMENTS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PG&E Corporation
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF EQUITY
Pacific Gas and Electric Company
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
NOTE 2: BANKRUPTCY FILING
NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NOTE 4 : REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
NOTE 5 : DEBT
NOTE 6 6: SB 901 SECURITI ZATION AND CUSTOMER CREDIT TRUST
NOTE 7 : COMMON STOCK AND SHARE-BASED COMPENSATION
NOTE 78 : PREFERRED STOCK
NOTE 89 : EARNINGS PER SHARE
NOTE 910 : INCOME TAXES
NOTE 101 1 : DERIVATIVES
NOTE 1 12 : FAIR VALUE MEASUREMENTS
NOTE 1 23 : EMPLOYEE BENEFIT PLANS
NOTE 1 34 : RELATED PARTY AGREEMENTS AND TRANSACTIONS
NOTE 141 5 : WILDFIRE-RELATED CONTINGENCIES
NOTE 1 56 : OTHER CONTINGENCIES AND COMMITMENTS
~~NOTE 16: SUBSEQUENT EVENTS~~
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID No. 34)
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
~~EXHIBIT INDEX~~
ITEM 16. FORM 10-K SUMMARY
SIGNATURES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION ("PARENT")
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS


Designated portions of the Joint Proxy Statement relating to the ~~2021~~2023 Annual Meetings of Shareholders			Part III (Items 10, 11, 12, 13 and 14)


1 Kilowatt (kW)	=	One thousand watts
1 Kilowatt-Hour (kWh)	=	One kilowatt continuously for one hour
1 Megawatt (MW)	=	One thousand kilowatts
1 Megawatt-Hour (MWh)	=	One megawatt continuously for one hour
1 Gigawatt (GW)	=	One million kilowatts
1 Gigawatt-Hour (GWh)	=	One gigawatt continuously for one hour
1 Kilovolt (kV)	=	One thousand volts
1 MVA	=	One megavolt ampere
1 Mcf	=	One thousand cubic feet
1 MMcf	=	One million cubic feet
1 Bcf	=	One billion cubic feet
1 MDth	=	One thousand decatherms


~~2020~~2022 Form 10-K			PG&E Corporation’s and ~~Pacific Gas and Electric Company’s combined~~the Utility’s joint Annual Report on Form 10-K for the year ended December 31, ~~2020~~2022
2021 Form 10-K			PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2021
AB			Assembly Bill
~~ABR~~AFUDC			~~alternate base rate~~allowance for funds used during construction
~~AFUDC~~Amended Articles			~~Allowance~~Amended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020, and for ~~Funds Used During Construction~~
~~ALJ~~			~~administrative law judge~~
AR			~~accounts receivable~~PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022
ARO			asset retirement obligation
ASU			accounting standard update issued by the ~~FASB (see below)~~
~~Backstop Party~~			~~a third-party investor party to a Backstop Commitment Letter~~Financial Accounting Standards Board
Bankruptcy Code			the United States Bankruptcy Code
Bankruptcy Court			the U.S. Bankruptcy Court for the Northern District of California
~~BPP~~			~~bundled procurement plan~~
CAISO			California Independent System Operator Corporation
Cal Fire			California Department of Forestry and Fire Protection
CAPP			California Arrearage Payment Program
CARB			California Air Resources Board
CARE			California Alternate Rates for Energy Program
CCA			Community Choice Aggregator
CCPA			California Consumer Privacy Act of 2018
CEC			California Energy Resources Conservation and Development Commission
CEMA			Catastrophic Event Memorandum Account
Chapter 11			~~chapter~~Chapter 11 of ~~title~~Title 11 of the U.S. Code
Chapter 11 Cases			the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Order			the order confirming ~~PG&E Corporation’s and~~ the ~~Utility’s and the Shareholder Proponents’ Joint Chapter 11~~ Plan, ~~of Reorganization,~~ dated as of June 20, 2020, with the Bankruptcy Court
Corporation Revolving Credit Agreement			Credit Agreement, dated as of July 1, 2020, as amended, by and among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent
CHT			Customer Harm Threshold
~~CPE~~			~~central procurement entities~~
CPIM			Core Procurement Incentive Mechanism
CPPMA			COVID-19 Pandemic Protections Memorandum Account
CPUC			California Public Utilities Commission
~~CRRs~~CRR			congestion revenue rights
~~CUE~~CVA			~~Coalition of California Utility Employees~~climate vulnerability assessment
~~CVA~~D&O Insurance			~~Climate Vulnerability Assessment~~directors’ and officers’ liability insurance
DA			Direct Access
~~DER~~			~~distributed energy resources~~
Diablo Canyon			Diablo Canyon nuclear power plant
~~DIP Credit Agreement~~District Court			~~Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as~~United States District Court for the Northern District of ~~February 1, 2019, among the Utility, as borrower, PG&E Corporation, as guarantor, JPM., as administrative agent, and Citibank, N.A., as collateral agent~~California
DOE			~~U.S.~~United States Department of Energy
DOJ			United States Department of Justice
DTA			deferred tax asset
DTSC			California Department of Toxic Substances Control
~~Effective~~DWR			California Department of Water Resources
EMANI			European Mutual Association for Nuclear Insurance
Emergence Date			July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
~~EMANI~~EOEP			~~European Mutual Association for Nuclear Insurance~~Enhanced Oversight and Enforcement Process


EPA			U.S. Environmental Protection Agency
EPS			earnings per common share
~~ERRA~~EPSS			~~Energy Resource Recovery Account~~

		Enhanced Powerline Safety Settings
EVEVM	~~electric vehicle~~enhanced vegetation management
~~FASB~~Exchange Act	~~Financial Accounting Standards Board~~
~~FEMA~~	~~Federal Emergency Management Agency~~Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
FHPMA	Fire Hazard Prevention Memorandum Account
Fire Victim Trust	The trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be, funded
~~Forward Stock Purchase Agreements~~First Mortgage Bonds	~~The prepaid forward contracts between PG&E Corporation and~~bonds issued pursuant to the ~~Backstop Parties~~Indenture of Mortgage, dated as of June 19, 2020 between the Utility and The Bank of New York Mellon Trust Company, N.A., as amended and supplemented
FRMMA	Fire Risk Mitigation Memorandum Account
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GO	general order
GRC	general rate case
GT&S	gas transmission and storage
~~HSM~~HFTD	~~hazardous substance memorandum account~~high fire threat district
HSMA	Hazardous Substance Memorandum Account
IRC	Internal Revenue Code of 1986, as amended
IOUs	investor-owned utility(ies)
~~Investment Agreement~~Kincade Amended Complaint	The ~~agreement between PG&E Corporation and~~amended criminal complaint filed by the ~~PIPE investors dated as of June 7, 2020 relating to~~Sonoma County District Attorney’s Office on January 28, 2022 in connection with the ~~issuance and sale to the PIPE Investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock~~
~~JPM~~	~~JPMorgan Chase Bank, N.A.~~
~~Knighthead~~	~~certain funds and accounts managed by Knighthead Capital Management, LLC~~2019 Kincade fire
Lakeside Building	300 Lakeside Drive, Oakland, California, 94612
~~LCC~~	~~Land Conservation Commitment~~
~~LIBOR~~	~~London Interbank Offered Rate~~
~~LSE~~LSEs	load serving entities
~~LSTC~~LTIP	~~liabilities subject to compromise~~
~~LTIP~~	~~PG&E Corporation 2014~~ Long-Term Incentive Plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
MGMA	Microgrids Memorandum Account
MGP	manufactured gas plants
~~the Monitor~~	~~third-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction~~
NAV	net asset value
~~NBC~~	~~Non-Bypassable Charge~~
NDCTP	Nuclear Decommissioning Cost Triennial ~~Proceedings~~Proceeding
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
~~Noteholder RSA~~New Shares	~~Restructuring Support~~Shares of PG&E Corporation common stock held by ShareCo that may be exchanged for Plan Shares as contemplated by the Share Exchange and Tax Matters Agreement ~~dated as of January 22, 2020 with certain holders of indebtedness of the Utility, among others~~
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
~~OES~~OEIS	~~State of California~~ Office of ~~Emergency Services~~Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OII	order instituting investigation
OIR	order instituting rulemaking
~~OSA~~Pacific Generation	~~Office~~Pacific Generation LLC, a subsidiary of the ~~Safety Advocate, a division of the CPUC~~
~~PAO~~	~~Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)~~Utility
PCAOB	Public Company Accounting Oversight Board (United States)
~~PCIA~~	~~Power Charge Indifference Adjustment~~


PD			proposed decision
PERA			Public Employees Retirement Association
~~Petition Date~~			~~January 29, 2019~~
~~PIPE Investor~~			~~a third-party investor party to the Investment Agreement~~
Plan			PG&E Corporation and the Utility, Knighthead Capital Management, LLC, and ~~the Shareholder Proponents’~~Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
~~POD~~Plan Shares			~~Presiding Officer’s Decision~~Shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan

~~PSA~~	~~plan support agreement~~
PSPS		Public Safety Power Shutoff
QF		Qualifying facilities
~~RAMP~~		~~Risk Assessment Mitigation Phase~~
RA		Resource Adequacy
Receivables Securitization Program		The accounts receivable securitization program entered into by the Utility on October 5, 2020, providing for the sale of a portion of the Utility’s accounts receivable and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions
ROE		return on equity
ROU asset		right-of-use asset
RPS		Renewables Portfolio Standard
~~RSA~~		~~restructuring support agreement~~
RTBA		Risk Transfer Balancing Account
RUBA		Residential Uncollectibles Balancing Account
SB		Senate Bill
SEC		U.S. Securities and Exchange Commission
Securities Act		The Securities Act of 1933, as amended
SED		Safety and Enforcement Division of the CPUC
~~Shareholder Proponents~~		~~Knighthead together with Abrams Capital Management, LP~~
SFGO		The Utility’s San Francisco General Office headquarters complex
~~SPD~~Share Exchange and Tax Matters Agreement		~~Safety Policy Division of~~Share Exchange and Tax Matters Agreement dated July 8, 2021 between PG&E Corporation, the ~~CPUC~~Utility, ShareCo and the Fire Victim Trust
ShareCo		PG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV		PG&E AR Facility, LLC
~~Subrogation RSA~~		~~Restructuring Support Agreement dated September 22, 2019 with certain holders of insurance subrogation claims, as amended~~
Tax Act		Tax Cuts and Jobs Act of 2017
~~TCC~~		~~Official Committee of Tort Claimants~~
~~TCC RSA~~		~~Restructuring Support Agreement dated December 6, 2019 with the TCC and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended~~
TE		~~transportation electrification~~
TO		transmission owner
TURN		The Utility Reform Network
USFS		United States Forest Service
Utility		Pacific Gas and Electric Company
Utility Revolving Credit Agreement		Credit Agreement, dated as of July 1, 2020, as amended, by and among the Utility, the several banks and other financial institutions or entities party thereto from time to time and Citibank, N.A., as Administrative Agent and Designated Agent
VIE(s)		variable interest entity(ies)
VMBA		Vegetation Management Balancing Account
VSP		voluntary separation program
WEMA		Wildfire Expense Memorandum Account
Wildfire Fund		statewide fund established by AB 1054 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
~~Wildfires OII~~		~~Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire~~
WMBA		Wildfire Mitigation Balancing Account
WMCE		Wildfire Mitigation and Catastrophic Events
WMP		wildfire mitigation plan
WMPMA		Wildfire Mitigation Plan Memorandum Account
~~WSD~~		~~Wildfire Safety Division~~


Source						Amount (metric ~~tonnes~~tons CO2 equivalent)
Fossil ~~Fuel-Fired Plants~~fuel-fired plants (1)						~~2,484,127~~2,485,379
Natural ~~Gas Compressor Stations~~gas compressor stations and ~~Storage Facilities~~storage facilities (2)						~~344,810~~322,047
Distribution ~~Fugitive Natural Gas Emissions~~fugitive natural gas emissions						~~496,789~~589,343
Customer ~~Natural Gas Use~~natural gas use (3)						~~42,058,499~~41,563,483


	2019	2018
Total NOx Emissions (tons)	135	134
NOx Emissions Rate (pounds/MWh)	0.01	0.01
Total SO2 Emissions (tons)	14	15
SO2 Emissions Rate (pounds/MWh)	0.001	0.001


		Percent of Bundled Retail Sales (estimated procurement)		CEC Reporting Methodology Reduction(2)		Percent of Bundled Retail Sales (estimated Power Content Label) (2)			Percent of customer retail sales (estimated procurement)		CEC reporting methodology adjustment(2)		Percent of customer retail sales (estimated Power Content Label) (2)
Owned Generation Facilities
Owned generation facilities								Owned generation facilities
Renewable (3)	Renewable (3)	1.3	%	—	%	1.3	%	Renewable (3)	2	%	—	%	2	%
Nuclear	Nuclear	42.8	%	—	%	42.8	%	Nuclear	49	%	—	%	49	%
Large Hydroelectric		9.7	%	—	%	9.7	%
Large hydroelectric								Large hydroelectric	7	%	—	%	7	%
Fossil fuel-fired (4)	Fossil fuel-fired (4)	17.9	%	12.2	%	5.7	%	Fossil fuel-fired (4)	18	%	(16)	%	2	%
Total	Total	71.7	%	12.2	%	59.5	%	Total	76	%	(16)	%	60	%

Third-Party Purchase Agreements
Third-party purchase agreements								Third-party purchase agreements
Renewable (3)	Renewable (3)	34.3	%	—	%	34.3	%	Renewable (3)	38	%	—	%	38	%
Large Hydroelectric		0.5	%	—	%	0.5	%
Large hydroelectric								Large hydroelectric	—	%	—	%	—	%
Fossil fuel-fired (4)	Fossil fuel-fired (4)	18.0	%	12.3	%	5.7	%	Fossil fuel-fired (4)	16	%	(14)	%	2	%
Total	Total	52.8	%	12.3	%	40.5	%	Total	54	%	(14)	%	40	%
Others, Net (2)(5)		(24.5)	%	(24.5)	%	—	%
Others, net (2)(5)								Others, net (2)(5)	(30)	%	30	%	—	%

TOTAL	TOTAL	100.0	%	—	%	100.0	%	TOTAL	100	%	—	%	100	%
Total Renewable Energy Resources (3)		35.6	%	—	%	35.6	%
Total renewable energy resources (3)								Total renewable energy resources (3)	40	%	—	%	40	%
GHG-free resources (6)								GHG-free resources (6)	96	%	—	%	96	%


Type	Percent of Customer Retail Sales (estimated procurement)(1)(2)
Biopower	5	%
Geothermal	—	%
RPS-Eligible Small Hydroelectric	2	%
Solar	24	%
Wind	9	%
Total	40	%


Type	GWh	Percent of Bundled Retail Sales (estimated procurement)		Percent of Bundled Retail Sales (estimated Power Content Label) (1)
Biopower	1,008	2.8	%	2.8	%
Geothermal	920	2.6	%	2.6	%
RPS-Eligible Small Hydroelectric	436	1.2	%	1.2	%
Solar	5,784	16.1	%	16.1	%
Wind	4,617	12.9	%	12.9	%
Total	12,765	35.6	%	35.6	%


	2020		2019		2018
Customers (average for the year)	5,498,044		5,457,101		5,428,318
Deliveries (in GWh) (1)	78,497		78,070		79,774
Revenues (in millions):
Residential	$	5,523	$	4,847	$	5,051
Commercial	4,722		4,756		4,908
Industrial	1,530		1,493		1,532
Agricultural	1,471		1,106		1,234
Public street and highway lighting	69		67		72
Other (2)	(130)		168		(720)
Subtotal	13,185		12,437		12,077
Regulatory balancing accounts (3)	673		303		636
Total operating revenues	$	13,858	$	12,740	$	12,713
Selected Statistics:
Average annual residential usage (kWh)	6,179		5,750		5,772
Average billed revenues per kWh:
Residential	$	0.1852	$	0.1762	$	0.1838
Commercial	0.1730		0.1585		0.1627
Industrial	0.1085		0.1015		0.1010
Agricultural	0.2210		0.2172		0.1968
Net plant investment per customer	$	8,889	$	8,375	$	7,950


	2022		2021		2020
Customers (average for the year)	5,562,223		5,539,969		5,498,044
Deliveries (in GWh) (1)	77,769		78,588		78,497
Revenues (in millions):
Residential	$	6,130	$	6,089	$	5,523
Commercial	5,416		5,042		4,722
Industrial	1,626		1,493		1,530
Agricultural	1,830		1,565		1,471
Public street and highway lighting	77		73		69
Other, net (2)	(247)		(84)		(130)
Subtotal	14,832		14,178		13,185
Regulatory balancing accounts (3)	228		953		673
Total operating revenues	$	15,060	$	15,131	$	13,858
Selected Statistics:
Average annual residential usage (kWh)	5,564		5,889		6,179
Average billed revenues per kWh:
Residential	$	0.2253	$	0.2125	$	0.1852
Commercial	0.1896		0.1802		0.1730
Industrial	0.1177		0.1075		0.1085
Agricultural	0.2435		0.2104		0.2210
Net plant investment per customer	$	9,967	$	9,199	$	8,889


Generation Type	County Location	Number of Units	Net Operating Capacity (MW)
Nuclear (1):
Diablo Canyon	San Luis Obispo	2	2,240
Hydroelectric (2):
Conventional	16 counties in northern and central California	100	2,655
Helms pumped storage	Fresno	3	1,212
Fossil fuel-fired:
Colusa Generating Station	Colusa	1	657
Gateway Generating Station	Contra Costa	1	580
Humboldt Bay Generating Station	Humboldt	10	163
Fuel Cell:
CSU East Bay Fuel Cell	Alameda	1	1
SF State Fuel Cell	San Francisco	2	2
Photovoltaic (3):	Various	13	152
Total		133	7,662


Date						Shares Exchanged
January 31, 2022						40,000,000
April 14, 2022						60,000,000
October 4, 2022						35,000,000
October 27, 2022						35,000,000
December 12, 2022						60,000,000
January 9, 2023						60,000,000
Total Shares Exchanged						290,000,000


	2022						2021
	Revenues and Costs:						Revenues and Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	10,357	$	4,703	$	15,060	$	9,542	$	5,589	$	15,131
Natural gas operating revenues	3,939		2,681		6,620		3,753		1,758		5,511
Total operating revenues	14,296		7,384		21,680		13,295		7,347		20,642
Cost of electricity	—		2,756		2,756		—		3,232		3,232
Cost of natural gas	—		2,100		2,100		—		1,149		1,149
Operating and maintenance	6,737		2,988		9,725		6,820		3,374		10,194
SB 901 securitization charges, net	608		—		608		—		—		—
Wildfire-related claims, net of insurance recoveries	237		—		237		258		—		258
Wildfire Fund expense	477		—		477		517		—		517
Depreciation, amortization, and decommissioning	3,856		—		3,856		3,403		—		3,403
Total operating expenses	11,915		7,844		19,759		10,998		7,755		18,753
Operating income (loss)	2,381		(460)		1,921		2,297		(408)		1,889
Interest income	162		—		162		22				22
Interest expense	(1,658)		—		(1,658)		(1,373)		—		(1,373)
Other income, net	135		460		595		104		408		512
Reorganization items, net	—		—		—		(12)		—		(12)
Income before income taxes	$	1,020	$	—	$	1,020	$	1,038	$	—	$	1,038
Income tax provision (benefit) (1)					(1,206)						900
Net income					2,226						138
Preferred stock dividend requirement (1)					14						14
Income Attributable to Common Stock					$	2,212					$	124


	2022		2021
Federal statutory income tax rate	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	(26.9)	%	24.1	%
Effect of regulatory treatment of fixed asset differences (2)	(49.2)	%	(51.6)	%
Tax credits	(1.3)	%	(1.2)	%
Fire Victim Trust (3)	(64.0)	%	91.9	%
Other, net	2.2	%	2.6	%
Effective tax rate	(118.2)	%	86.8	%


	Payment due by period
(in millions)	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Utility
Long-term debt (1)	$	4,043	$	7,778	$	4,209	$	35,895	$	51,925
Purchase obligations (2)
Power purchase agreements	2,917		4,896		4,198		21,657		33,668
Natural gas supply, transportation, and storage	466		349		302		184		1,301
Nuclear fuel agreements	64		103		47		—		214
Pension and other benefits (3)	342		684		684		342		2,052
Operating leases (2)	42		80		129		3,019		3,270
Preferred dividends (4)	14		28		28		—		70
PG&E Corporation
Long-term debt (1)	—		—		2,901		2,000		4,901
Total Contractual Commitments	$	7,888	$	13,918	$	12,498	$	63,097	$	97,401


(in millions) Lines of Business:	Amounts Approved in Final Decision		Increase/ (Decrease) 2019 vs. Final Decision
Electric distribution	$	4,800	$	436
Gas distribution	2,013		51
Electric generation	2,289		98
Total revenue requirements	$	9,102	$	585

Cost Category:
Operations and maintenance	$	2,073	$	128
Customer services	277		(61)
Administrative and general	1,203		250
Less: Revenue credits	(195)		(42)
Franchise fees, taxes other than income, and other adjustments	214		32
Depreciation (including costs of asset removal), return, and income taxes	5,530		278
Total revenue requirements	$	9,102	$	585


(in millions)	Exposure (1)		Number of Wholesale Customers or Counterparties >10%	Net Credit Exposure to Wholesale Customers or Counterparties >10%
December 31, 2020	$	250	2	$	57
December 31, 2019 (2)	$	381	3	$	36


(in millions)	Increase (Decrease) in Assumption		Increase in 2020 Pension Costs		Increase in Projected Benefit Obligation at December 31, 2020
Discount rate	(0.50)	%	$	77	$	1,979
Rate of return on plan assets	(0.50)	%	92		—
Rate of increase in compensation	0.50	%	43		435


(in millions)	Increase (Decrease) in Assumption		Increase in 2020 Other Postretirement Benefit Costs		Increase in Accumulated Benefit Obligation at December 31, 2020
Health care cost trend rate	0.50	%	$	9	$	66
Discount rate	(0.50)	%	11		150
Rate of return on plan assets	(0.50)	%	13		—


	Common Stock			Treasury Stock			Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity		Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
	Shares	Amount		Shares	Amount
Balance at December 31, 2019	529,236,741	$	13,038	—	$	—	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388
Net loss	—	—		—	—		(1,304)		—		(1,304)		—		(1,304)
Other comprehensive loss	—	—		—	—		—		(17)		(17)		—		(17)
Common stock issued, net	1,455,441,932	15,854		—	—		—		—		15,854		—		15,854
Equity units issued	—	1,304		—	—		—		—		1,304		—		1,304
Stock-based compensation amortization	—	28		—	—		—		—		28		—		28
Balance at December 31, 2020	1,984,678,673	$	30,224	—	$	—	$	(9,196)	$	(27)	$	21,001	$	252	$	21,253
Net loss	—	—		—	—		(88)		—		(88)		—		(88)
Other comprehensive income	—	—		—	—		—		7		7		—		7
Common stock issued, net (1)	721,867	4,854		—	—		—		—		4,854		—		4,854
Treasury stock acquired	—	—		477,743,590	(4,854)		—		—		(4,854)				(4,854)
Stock-based compensation amortization	—	51		—	—		—		—		51		—		51
Balance at December 31, 2021	1,985,400,540	$	35,129	477,743,590	$	(4,854)	$	(9,284)	$	(20)	$	20,971	$	252	$	21,223
Net income	—	—		—	—		1,814		—		1,814		—		1,814
Other comprehensive income	—	—		—	—		—		15		15		—		15
Common stock issued, net	2,384,408	(2,337)		—	—		—		—		(2,337)		—		(2,337)
Treasury stock disposition	—	—		(230,000,000)	2,337		—		—		2,337		—		2,337
Stock-based compensation amortization	—	95		—	—		—		—		95		—		95
Preferred stock dividend requirement of subsidiary in arrears	—	—		—	—		(59)		—		(59)		—		(59)
Preferred stock dividend requirement of subsidiary	—	—		—	—		(13)		—		(13)		—		(13)
Balance at December 31, 2022	1,987,784,948	$	32,887	247,743,590	$	(2,517)	$	(7,542)	$	(5)	$	22,823	$	252	$	23,075


	Common Stock Shares	Common Stock Amount		Reinvested Earnings		Accumulated Other Comprehensive Loss		Total Shareholders' Equity		Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
Balance at December 31, 2017	514,755,845	$	12,632	$	6,596	$	(8)	$	19,220	$	252	$	19,472
Net loss	—	—		(6,837)		—		(6,837)		—		(6,837)
Other comprehensive income (loss)	—	—		5		(1)		4		—		4
Common stock issued, net	5,582,865	200		—		—		200		—		200
Stock-based compensation amortization	—	78		—		—		78		—		78
Preferred stock dividend requirement of subsidiary	—	—		(14)		—		(14)		—		(14)
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


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,458)	$	(7)	$	(773)
Income taxes, net	0		0		(59)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	515	$	826	$	368
Operating lease liabilities arising from obtaining ROU assets	13		2,807		0
Common stock equity infusion from PG&E Corporation used to satisfy liabilities	6,750		0		0


	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2017	$	258	$	1,322	$	8,505	$	9,656	$	6	$	19,747
Net loss	—		—		—		(6,818)		—		(6,818)
Other comprehensive income (loss)	—		—		—		2		(7)		(5)
Equity contribution	—		—		45		—		—		45
Preferred stock dividend	—		—		—		(14)		—		(14)
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


(in millions)	Utility		PG&E Corporation (1)		December 31, 2019 PG&E Corporation Consolidated		Change in Estimated Allowed Claim 2020 (2)		Cash Payment		Reclassified as of June 30, 2020 (3)		Utility		PG&E Corporation (1)		December 31, 2020 PG&E Corporation Consolidated
Financing debt	$	22,450	$	666	$	23,116	$	351	$	0	$	(23,467)	$	0	$	0	$	0
Wildfire-related claims	25,548		0		25,548		18		(23)		(25,543)		0		0		0
Trade creditors (4)	1,183		5		1,188		6		(14)		(1,180)		0		0		0
Non-qualified benefit plan	20		137		157		0		0		(157)		0		0		0
2001 bankruptcy disputed claims	234		0		234		4		0		(238)		0		0		0
Customer deposits & advances	71		0		71		12		0		(83)		0		0		0
Other	230		2		232		59		0		(291)		0		0		0
Total Liabilities Subject to Compromise	$	49,736	$	810	$	50,546	$	450	$	(37)	$	(50,959)	$	0	$	0	$	0


	Year Ended December 31, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	6	$	0	$	6
Legal and other (2)	318		1,651		1,969
Interest and other	(14)		(2)		(16)
Total reorganization items, net	$	310	$	1,649	$	1,959


	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


	Year Ended
(in millions)	2020		2019
Electric
Revenue from contracts with customers
Residential	$	5,523	$	4,847
Commercial	4,722		4,756
Industrial	1,530		1,493
Agricultural	1,471		1,106
Public street and highway lighting	69		67
Other (1)	(130)		168
Total revenue from contracts with customers - electric	13,185		12,437
Regulatory balancing accounts (2)	673		303
Total electric operating revenue	$	13,858	$	12,740

Natural gas
Revenue from contracts with customers
Residential	$	2,517	$	2,325
Commercial	597		605
Transportation service only	1,211		1,249
Other (1)	61		123
Total revenue from contracts with customers - gas	4,386		4,302
Regulatory balancing accounts (2)	225		87
Total natural gas operating revenue	4,611		4,389
Total operating revenues	$	18,469	$	17,129


	Estimated Useful	Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)	2020		2019
Electricity generating facilities (1)	5 to 75	$	13,751	$	13,189
Electricity distribution facilities	10 to 70	37,675		35,237
Electricity transmission facilities	15 to 75	15,556		14,281
Natural gas distribution facilities	20 to 60	15,133		14,236
Natural gas transmission and storage facilities	5 to 66	9,002		8,452
Construction work in progress		2,757		2,675
Other		18		18
Total property, plant, and equipment		93,892		88,088
Accumulated depreciation		(27,756)		(26,453)
Net property, plant, and equipment		$	66,136	$	61,635


	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2022		2021
Electricity generating facilities (1)	5 to 75	$	11,781	$	11,217
Electricity distribution facilities	10 to 70	41,061		37,723
Electricity transmission facilities	15 to 75	16,413		15,516
Natural gas distribution facilities	20 to 60	15,366		14,100
Natural gas transmission and storage facilities	5 to 66	9,859		9,067
Financing lease		18		18
Construction work in progress		4,137		3,480
General plant and other	5 to 50	8,518		7,838
Total property, plant, and equipment		107,153		98,959
Accumulated depreciation		(30,946)		(29,131)
Net property, plant, and equipment (2)		$	76,207	$	69,828


(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)		0		(17)
Ending balance	$	(39)	$	17	$	(22)