The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to liabilities subject to compromise, insurance receivable, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors below and a detailed discussion of these matters contained in Item 2. MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “PG&E Progress,” “Chapter 11,” “Wildfire Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in 1 segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2019 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2019 Form 10-K. This quarterly report should be read in conjunction with the 2019 Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s ~~wildfire-related liabilities,~~ regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, ~~insurance receivables,~~the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan ~~obligations, and the valuation of LSTC.~~obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

The accompanying Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. ~~However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty.~~ PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 ~~protection. See Note 10 below.~~protection on January 29, 2019. Uncertainty regarding these matters ~~raises~~previously raised substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. ~~PG&E Corporation and the Utility have determined that commencing reorganization cases under Chapter 11 was necessary to restore~~

As a result of PG&E Corporation’s and the Utility’s financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation’s and the Utility’s financial stability.

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

~~Under~~Except as otherwise set forth in the ~~Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation~~Plan, the Confirmation Order (as defined below) or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 10 below) as of the Petition Date, are subject to an automatic stay. Absent ananother order of the Bankruptcy Court, ~~providing otherwise,~~ substantially all pre-petition liabilities ~~will be resolved under a Chapter 11 plan of reorganization to be voted upon by impaired creditors and interest holders, and approved by the Bankruptcy Court. However,~~were discharged under the ~~Bankruptcy Code, regulatory or criminal proceedings generally are not subject to an automatic stay, and these proceedings have been continuing during the pendency of the Chapter 11 Cases.~~

On January 31, 2019, the Bankruptcy Court approved, on an interim basis, certain motions (the “First Day Motions”) authorizing, but not directing, PG&E Corporation and the Utility to, among other things, (a) secure $5.5 billion of debtor-in-possession financing; (b) continue to use PG&E Corporation’s and the Utility’s cash management system; and (c) pay certain pre-petition claims relating to (i) certain safety, reliability, outage, and nuclear facility suppliers; (ii) shippers, warehousemen, and other lien claimants; (iii) taxes; (iv) employee wages, salaries, and other compensation and benefits; and (v) customer programs, including public purpose programs. The First Day Motions were subsequently approved by the Bankruptcy Court on a final basis at hearings on February 27, 2019, March 12, 2019, March 13, 2019, and March 27, 2019.

On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with certain holders of wildfire insurance subrogation claims (collectively, the “Consenting Subrogation Creditors”). On September 22, 2019, PG&E Corporation and the Utility and the Consenting Subrogation Creditors entered into an amended and restated Restructuring Support Agreement, which was subsequently amended on November 1, 2019, (as amended, the “Subrogation RSA”~~). The Subrogation RSA provides for an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) to be paid by PG&E Corporation~~, and ~~the Utility pursuant to the Plan in order to settle all insurance subrogation~~such claims, ~~(the~~the “Subrogation Claims”) relating to the 2017 Northern California wildfires and the 2018 Camp fire (the “Subrogation Claims Settlement”), upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also have agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the Subrogation RSA. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the Subrogation RSA and approval of the Subrogation Claims Settlement. Hearings on PG&E Corporation’s and the Utility’s motion to approve the Subrogation RSA were held on October 23, 2019, December 4, 2019 and December 17, 2019.. On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA. As of September 30, 2020, PG&E Corporation and the Utility incurred $53 million in professional fees related to the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the Subrogation RSA.

On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019 (as amended, the “TCC RSA”), with the TCC, the attorneys and other advisors and agents for holders of Fire Victim Claims (as defined below) that are signatories to the TCC RSA (each a “Consenting Fire Claimant Professional”), and the Shareholder Proponents. The TCC RSA provides for, among other things, an aggregate of $13.5 billion in value to be provided by PG&E Corporation and the Utility pursuant to the Plan in order to settle and discharge all claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and ~~the~~ Public Entity Wildfire ~~Claims)~~Claims (as defined below)) (the “Fire Victim Claims”)~~, upon the terms and conditions set forth in~~ that are signatories to the TCC RSA, and the Plan. On December 9, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the TCC RSA. A hearing on PG&E Corporation’s and the Utility’s motion to approve the TCC RSA was held on December 17, 2019.Shareholder Proponents. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 10 for further information on the TCC RSA.

On January 22, 2020, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” therein and the Shareholder Proponents (the “Noteholder RSA”). On February 5, 2020, the Bankruptcy Court entered an order approving the Noteholder RSA.

The Plan ~~proposes~~as confirmed by the ~~following:~~Confirmation Order provides for certain transactions and the satisfaction and treatment of claims against and interests in PG&E Corporation and the Utility, each in accordance with the terms of the Plan, including the transactions described below. The Plan provides for the following treatment of various classes of claims as described below. PG&E Corporation and the Utility are in the process of resolving and paying claims pursuant to the treatment provided under the Plan.

In addition, the Plan also provides for the ~~holders~~following in connection with or following the implementation of the Plan:

•~~future participation~~The Confirmation Order contains a channeling injunction that is also in the ~~state wildfire fund established by AB 1054;~~Plan that provides, among other things, that the sole source of recovery for holders of Subrogation Claims will be from the Subrogation Wildfire Trust and

The Plan ~~proposes~~as confirmed by the ~~following key~~Confirmation Order provides for certain financing ~~sources:~~transactions as follows:

The ~~Plan has not been approved and is subject to regulatory review by~~foregoing financing transactions occurred on or around the CPUC and FERC, as and to the extent required by law, including as potentially causing a change in control under Section 203 of the Federal Power Act. The Plan may be further amended, modified, or supplemented as necessary or desired by PG&E Corporation and the Utility or as required by the Bankruptcy Court or the CPUC. PG&E Corporation and the Utility expect that the CPUC and FERC will issue decisions in advance of the June 30, 2020 deadline for Plan confirmation.Effective Date.

On the Effective Date, pursuant to the Plan, ~~is scheduled~~the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for ~~May 27, 2020.~~fiscal year 2020 to be paid on or before January 15, 2021 (the “First Payment Date”) and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022.

~~Restructuring Support Agreement~~Also on the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the ~~Ad Hoc Noteholder Committee~~Fire Victim Trust, pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477 million shares (such shares, the “Fire Victim Trust Shares”) of common stock of PG&E Corporation, no par value (the “Common Stock”). As a result of the Equity Units Underwriters exercising their option to purchase 1.45 million additional Equity Units, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with the Fire Victim Trust.

•~~Utility Reinstated Senior Notes: The remaining outstanding $9.575~~In connection with its emergence from Chapter 11 in July 2020, PG&E raised an aggregate of $9.0 billion ~~aggregate principal amount~~ of ~~Utility notes (the “Utility Reinstated Senior Notes”) will be reinstated on their contractual terms, including being secured equally and ratably with~~gross proceeds through the ~~New Utility Short-Term Notes and the New Utility Long-Term Notes.~~

As of March 6, 2020, PG&E Corporation ~~has~~ entered into Chapter 11 Plan Backstop Commitment Letters (collectively, as amended by the Consent Agreements (as defined below), the “Backstop Commitment Letters”) with investors (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). The price at which any such new shares would be issued to the Backstop Parties would be equal to (a) 10 (subject to adjustment as provided in the Backstop Commitment Letters), times (b) PG&E Corporation’s consolidated Normalized Estimated Net Income (as defined in the Backstop Commitment Letters) for the estimated year 2021, divided by (c) the number of fully diluted sharesAs a result of PG&E Corporation ~~that will be outstanding~~emerging from Chapter 11 on ~~the effective date of the Plan (the “Effective Date”) (assuming that all equity is raised by funding~~July 1, 2020, the Backstop ~~Commitments).~~Commitments were not utilized and terminated in accordance with their terms.

The Backstop Commitment Letters provide that, under certain circumstances, PG&E Corporation and the Utility will be permitted to issue new shares of common stock of PG&E Corporation for up to $12.0 billion of proceeds to finance the transactions contemplated by the Plan through one or more equity offerings that, under certain circumstances, must include a rights offering (the “Rights Offering”). The structure, terms and conditions of any such equity offering (including a Rights Offering) are expected to be determined by PG&E Corporation and the Utility at a later time in the Chapter 11 process, subject to the terms and conditions of the Backstop Commitment Letters. This may include terms and conditions that are designed to preserve the ability of PG&E Corporation or the Utility to utilize their net operating loss carryforwards. There can be no assurance that any such equity offering would be successful. In the event that such equity offerings (together with additional permitted capital sources) do not raise at least $12.0 billion of proceeds in the aggregate or if PG&E Corporation and the Utility do not otherwise consummate such offerings, then PG&E Corporation and the Utility may draw on the Backstop Commitments for equity funding to finance the transactions contemplated by the Plan, subject to the satisfaction or waiver by the Backstop Parties of the conditions set forth therein. Although the Backstop Commitment Letters permit PG&E Corporation to draw up to $12.0 billion in equity under specified circumstances, the Plan contemplates an equity raise of only $9.0 billion, the maximum available under these circumstances, which equity will be raised in accordance with the terms of the Backstop Commitment Letters.

On June 30, 2020, PG&E Corporation recorded approximately $1.1 billion of ~~additional shares in the event that the aggregate value of the 119 million shares paid as~~expense related to the Backstop Commitment premium ~~is less than $764 million~~in Reorganization items, net. This amount was primarily based on ~~the market~~PG&E Corporation’s closing stock price on June 30, 2020 of ~~the Corporation’s common stock following~~$8.87 per share. On the Effective Date, ~~subject to~~PG&E Corporation’s closing price was $9.03 per share and as a cap of 19,909,091 additional shares in total. Such commitment premium was earned in full upon Bankruptcy Court approval of the Backstop Commitment Letters, subject to clawback under certain circumstances set forth in the Backstop Commitment Letters. In the event that a plan of reorganization forresult, PG&E Corporation ~~that is not the Plan is confirmed by the Bankruptcy Court, then the Backstop Commitment premium will be payable in cash if elected by the applicable Backstop Party.~~ recorded an additional $19 million expense as of September 30, 2020.

Under the Backstop Commitment Letters, PG&E Corporation and the Utility have also agreed to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the aggregate for the legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters.

In connection with PG&E Corporation’s underwritten offerings of up to $5.75 billion of equity securities to finance the ~~anticipated funding for~~transactions contemplated by the Plan ~~and~~(the “Offerings”), up to $523 million was issuable pursuant to customary options granted to the ~~anticipated amount of debt and equity~~underwriters thereof to ~~be used for funding thereunder, on February 14, 2020,~~purchase the Debt Commitment Letters were amended to, among other things, (1) adjust the maximum amount of any roll-over, “take-back” or reinstated debt permitted under the Facilities from $30 billion to $33.35 billion at the Utility and from $7.0 billion to $5.0 billion at PG&E Corporation and (2) increase the amount of proceeds from the issuance of debt securities or other debt for borrowed money as a condition to funding from $2.0 billion at PG&E Corporation to $6.0 billion at the Utility.

~~In lieu of entering into the Facilities,~~On June 19, 2020, PG&E Corporation entered into prepaid forward contracts (the “Forward Stock Purchase Agreements”) with the Backstop Parties. Each Forward Stock Purchase Agreement provided that, subject to certain conditions, the Backstop Party will purchase on the Effective Date, and receive on the ~~Utility intend~~Settlement Date (as defined in each Forward Stock Purchase Agreement) an amount of common stock of PG&E Corporation equal to ~~obtain permanent financing on or prior to emergence from bankruptcy~~its pro rata share of the value of the Option Securities not purchased by the underwriters (such amount, each Backstop Party’s “Greenshoe Backstop Purchase Amount” and all Greenshoe Backstop Purchase Amounts in the ~~form~~aggregate, the “Aggregate Greenshoe Backstop Purchase Amount”), at a price per share equal to the lesser of ~~bank facilities, debt securities or a combination~~(i) the lowest per share price of common stock sold on an underwritten basis to the public in an offering of common stock of PG&E Corporation, as disclosed on the cover page of the ~~foregoing.~~prospectus or prospectus supplement, and (ii) the price per share payable by the investors party to the Investment Agreement dated as of June 7, 2020 (such lesser price, the “Settlement Price”). The Settlement Price was $9.50 per share. Each Forward Stock Purchase Agreement expired on August 3, 2020.

On ~~March 16,~~June 25, 2020, the ~~Bankruptcy Court approved~~Backstop Parties funded the ~~Debt Commitment Letters as amended through February 28, 2020. During~~Greenshoe Backstop Purchase Amount to PG&E Corporation in the ~~three months ended March 31,~~amount of $523 million which was recorded in Other current liabilities on the Condensed Consolidated Financial Statements. PG&E Corporation applied the proceeds of such funding to distributions under the Plan on the Effective Date. On August 3, 2020, PG&E Corporation ~~and~~redeemed $120.5 million of the ~~Utility~~Forward Stock Purchase Agreements payable in cash as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement (as defined below in Note 6). On August 3, 2020, PG&E Corporation delivered 42.3 million shares of PG&E Corporation common stock to the Backstop Parties to settle the portion of the Forward Stock Purchase Agreements that was not redeemed.

Additionally, each Forward Stock Purchase Agreement provided that, subject to the consummation by PG&E Corporation of the Offerings, PG&E Corporation would issue to each Backstop Party its pro rata share of 50 million shares of common stock (such shares, each Backstop Party’s “Additional Backstop Premium Shares”). The Additional Backstop Premium Shares were issued to Backstop Parties on the Effective Date. On June 30, 2020, PG&E Corporation recorded ~~facility fees~~$444 million of ~~$36 million and $14 million, respectively, reflected~~expense related to the Additional Backstop Premium Shares in Reorganization items, ~~net~~net. This amount was based primarily on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the ~~Condensed Consolidated Income Statements. In addition, the Utility recorded $18 million to~~Effective Date, PG&E Corporation’s closing stock price was $9.03 per share and as a ~~regulatory asset for fees that are deemed probable of recovery.~~

Effective on the Petition Date and up to June 30, 2020, PG&E Corporation and the Utility ~~began to apply~~applied accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that ~~are~~was directly associated with reorganization proceedings must behave been reported separately as reorganization items, net in the Condensed Consolidated Statements of Income. In addition, the balance sheet must ~~distinguish~~have distinguished pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that ~~are~~were not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that ~~are~~were not debtors in the Chapter 11 Cases in the Condensed Consolidated Balance Sheets. LSTC are pre-petition obligations that ~~are~~were not fully secured and ~~have~~had at least a possibility of not being repaid at the full claim amount. Where there iswas uncertainty about whether a secured claim ~~will~~would be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility ~~have~~ classified the entire amount of the claim as LSTC.

Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. ~~While operating as debtors-in-possession,~~Pursuant to the Plan and Confirmation Order, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date ~~are stayed while PG&E Corporation~~were subject to an injunction and were subject to treatment under the ~~Utility continue business operations as debtors-in-possession.~~Plan. These claims ~~are~~were reflected as LSTC in the Condensed Consolidated Balance Sheets at ~~March~~December 31, ~~2020.~~2019. Additional claims ~~(which could be LSTC)~~ may arise after the Petition Date resulting from the rejection of executory contracts, including leases, and from the determination by the Bankruptcy Court (or agreement by parties-in-interest) of allowed claims for contingencies and other unliquidated and disputed amounts.

PG&E Corporation’s Condensed Consolidated Financial Statements are presented on a consolidated basis and include the accounts of PG&E Corporation and the Utility and other subsidiaries of PG&E Corporation and the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

The Utility’s Condensed Consolidated Financial Statements are presented on a consolidated basis and include the accounts of the Utility and other subsidiaries of the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

Upon emergence from Chapter 11 on July 1, 2020, PG&E Corporation and the Utility were not required to apply fresh start accounting based on the provisions of ASC 852 since the entity’s reorganization value immediately before the date of confirmation is more than the total of all its post-petition liabilities and allowed claims.

As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities iswas subject to compromise or other treatment pursuant to ~~a plan of reorganization.~~the Plan. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities ~~are stayed. Although payment of pre-petition claims generally is not permitted,~~were subject to an injunction and will be satisfied pursuant to the ~~Bankruptcy Court granted PG&E Corporation~~Plan and the ~~Utility authority to pay certain pre-petition~~Chapter 11 claims in designated categories and subject to certain terms and conditions. This relief generally was designed to preserve the value of PG&E Corporation’s and the Utility’s business and assets. As described above, among other things, the Bankruptcy Court authorized, but did not require, PG&E Corporation and the Utility to pay certain pre-petition claims relating to employee wages and benefits, taxes, and amounts owed to certain vendors.reconciliation process.

The determination of how liabilities will ultimately be settled or treated cannot be made until the Bankruptcy Court confirms a Chapter 11 plan of reorganization and such plan becomes effective. Accordingly, the ultimate amount of such liabilities is not determinable at this time. GAAP requiresPrior to June 30, 2020, pre-petition liabilities that ~~are~~were subject to compromise were required to be reported at the amounts expected to be ~~allowed by the Bankruptcy Court, even if they may be settled for different amounts. The amounts currently classified as LSTC are preliminary and may be~~allowed. Therefore, liabilities subject to ~~future adjustments depending on Bankruptcy Court actions, further developments with respect~~compromise as of December 31, 2019 in the table below reflected management’s estimates of amounts expected to ~~disputed claims, determinations of~~be allowed in the ~~secured~~Chapter 11 Cases, based upon, among other things, the status of ~~certain claims, the values~~negotiations with creditors. As of ~~any collateral securing~~June 30, 2020, such ~~claims, rejection of executory contracts, continued reconciliation~~amounts were reclassified to current or ~~other events.~~

Liabilities subject to compromise as of December 31, ~~2020:~~2019 which were settled or reclassified during the nine months ended September 30, 2020 consist of the following:

PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition ~~Date.~~Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims including litigation claims, trade creditor claims, non-qualified benefit plan claims, ~~claims arising from the Utility’s 2001 Chapter 11 case and customer deposits and advances,~~ along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the ~~amount recorded~~amounts asserted in ~~liabilities subject~~such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to ~~compromise. To~~confirmation, other than as provided in the ~~extent~~Plan or the Confirmation Order.

The Plan, however, provides that the holders of certain claims may pursue their claims against PG&E Corporation and the Utility ~~believe~~on or after the Effective Date, including, but not limited to, the following:

Furthermore, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy ~~Court,~~Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility ~~will continue~~on or after the Effective Date, including but not limited to, ~~record~~ claims arising from or relating to:

In addition, claims continue to be pursued against PG&E Corporation and the Utility ~~continue to resolve claims, differences between those final allowed claims~~ and certain of their respective current and former directors and officers as well as certain underwriters, in connection with 3 purported securities class actions, as further described in Note 10 under the liabilities recorded in the Condensed Consolidated Balance Sheet will be recognized in PG&E Corporation’s and the Utility’s Statement of Consolidated Income (Loss) as they are resolved. The determination of how liabilities will ultimately be resolved cannot be made until the Bankruptcy Court approves a plan of reorganization or approves orders related to settlement of specific liabilities. Accordingly, the ultimate amount or resolution of such liabilities is not determinable at this time. The resolution of such claims could result in substantial adjustments to PG&E Corporation’s and the Utility’s financial statements.heading “Securities Class Action Litigation.”

For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 2 of the Condensed Consolidated Financial Statements above for bankruptcy-related policies and Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

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

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at ~~March 31,~~September 30, 2020, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at ~~March 31,~~September 30, 2020, it did not consolidate any of them.

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019 were as follows:

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

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

~~On February 27, 2019, PG&E Corporation~~Pursuant to the Plan and ~~the Utility received final approval from the Bankruptcy Court to maintain~~Confirmation Order, all existing pension and other benefit plans ~~other than~~were deemed assumed by PG&E Corporation and the ~~non-qualified pension plan, during the pendency of the Chapter 11 Cases.~~Utility.

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

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

The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and ~~its~~ GT&S rate cases, which generally occur every three or four years. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

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

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

On the Effective 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. As of September 30, 2020, PG&E Corporation and the Utility have 9 remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as 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 calendar 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.

In the second quarter of 2020, PG&E Corporation and the Utility recorded a current liability of $5.2 billion in “Wildfire fund liability” and $1.5 billion in Other noncurrent liabilities for the present value of unpaid contribution amounts, as well as $6.5 billion in assets for its commitment to make contributions, reduced by amortization, of which $6.0 billion were non-current, called “Wildfire fund asset” in the Condensed Consolidated Balance Sheets. The initial contribution and first annual contribution were paid in the third quarter of 2020. During the three and nine months ended September 30, 2020, the Utility recorded amortization and accretion expense of $120 million and $293 million, respectively. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in “Wildfire fund expense” in the Condensed Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US 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 starting with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment. 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 of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Using a 5 year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would decrease the amortization period to 6 years. Similarly, a 10 percent change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility evaluate all assumptions quarterly, or 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 in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment 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. At September 30, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.

PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in its estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. ~~There was no material impact to PG&E Corporation or~~During the ~~Utility’s~~three and nine months ended September 30, 2020, expected credit losses of $33 million and $96 million, respectively, were recorded in Operating and maintenance expense on the Condensed Consolidated ~~Financial~~ Statements ~~resulting from~~of Income for credit losses associated with trade receivables. Of these amounts recorded during the ~~adoption~~three and nine months ended September 30, 2020, $17 million and $48 million, respectively, were deemed probable of ~~this ASU.~~

Long-term regulatory assets are comprised of the following:

Long-term regulatory liabilities are comprised of the following:

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

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A. (“JPM”), as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the “DIP Lenders”). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. The DIP Credit Agreement also provides for up to $4.0 billion of incremental facilities in the form of (i) one or more additional tranches of term loans or (ii) one or more increases in the aggregate amount of revolving commitments under the DIP Revolving Facility (together, the “Incremental Facilities”), subject to the terms and conditions set forth therein. The Incremental Facilities are uncommitted and would require approval from the Bankruptcy Court.thereto.

On ~~the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of~~July 1, 2020, the DIP Facilities ~~which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities~~were repaid in full and ~~the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility~~all commitments thereunder were terminated in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to the Utility. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement.connection with emergence from Chapter 11.

The following table summarizes PG&E Corporation’s and the Utility’s outstanding ~~debt~~borrowings and availability under their credit facilities at September 30, 2020:

^{Borrowings under the Utility Revolving Credit Facility bear interest based on the Utility’s election of either (1)}LIBOR plus an applicable margin of 1.375% to 2.50% based on the Utility’s credit rating or (2) the base rate plus an applicable margin of 0.375% to 1.50% based on the Utility’s credit rating. In addition to interest on outstanding principal under the Utility Revolving Credit Facility, the Utility is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.25% to 0.50% per annum depending on the Utility’s credit rating. The Utility Revolving Credit Facility has a maximum letter of credit sublimit equal to $1.5 billion. The Utility may also pay customary letter of credit fees based on letters of credit issued under the Utility Revolving Credit Facility.

The Utility Revolving Credit Facility includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, and (4) fundamental changes. In addition, the Utility Revolving Credit Facility requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of September 30, 2020, the Utility was in compliance with this covenant.

In the event of a default by the Utility under the Utility Revolving Credit Facility, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the designated agent may, with the consent of the required lenders (or upon the request of the required lenders), declare the amounts outstanding under the Utility Revolving Credit Facility, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Revolving Credit Facility become payable immediately.

The Utility may voluntarily repay outstanding loans under the Utility Revolving Credit Facility at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary prepayments made by the Utility will not reduce the commitments under the Utility Revolving Credit Facility.

In addition, on July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Facility”) with JPM, as administrative agent. The credit facilities under the Utility Term Loan Credit Facility 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 for the 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The Utility borrowed the entire amount of the Utility 364-Day Term Loan Facility and the Utility 18-Month Term Loan Facility on July 1, 2020. The proceeds were used to fund transactions contemplated under the Plan.

Borrowings under the Utility Term Loan Credit Facility bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 2.00% with respect to the Utility 364-Day Term Loan Facility and 2.25% with respect to the Utility 18-Month Term Loan Facility, or (2) the base rate plus an applicable margin of 1.00% with respect to the Utility 364-Day Term Loan Facility and 1.25% with respect to the Utility 18-Month Term Loan Facility.

The Utility Term Loan Credit Facility includes usual and customary provisions for term loan agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) fundamental changes, (5) entering into swap agreements and (6) modifications to the Utility’s mortgage indenture. In addition, the Utility Term Loan Credit Facility will require that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of September 30, 2020, the Utility was in compliance with this covenant.

In the event of a default by the Utility under the Utility Term Loan Credit Facility, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Utility Term Loan Credit Facility, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Term Loan Credit Facility become payable immediately.

The Utility is required to prepay outstanding term loans under the Utility Term Loan Credit Facility (with all outstanding term loans made under the Utility 364-Day Term Loan Facility being paid first), subject to certain exceptions, with 100% of the net cash proceeds of certain securitization transactions. The Utility may voluntarily repay outstanding loans under the Utility Term Loan Credit Facility at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans.

Borrowings under the Corporation Revolving Credit Facility bear interest based on PG&E Corporation’s election of either (1) LIBOR plus an applicable margin of 3.00% to 4.25% based on PG&E Corporation’s credit rating or (2) the base rate plus an applicable margin of 2.00% to 3.25% based on PG&E Corporation’s credit rating. In addition to interest on outstanding principal under the Corporation Revolving Credit Facility, PG&E Corporation is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.50% to 0.75% per annum depending on PG&E Corporation’s credit rating.

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

The Corporation Revolving Credit Facility includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) investments, (5) dispositions, (6) changes in the nature of business, (7) transactions with affiliates, (8) burdensome agreements, (9) restricted payments, (10) fundamental changes, (11) use of proceeds, (12) entering into swap agreements and (13) the ability to dispose of common stock of the Utility. In addition, the Corporation Revolving Credit Facility will require 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.

In the event of a default by PG&E Corporation under the Corporation Revolving Credit Facility, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Corporation Revolving Credit Facility, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Corporation Revolving Credit Facility become payable immediately.

PG&E Corporation may voluntarily repay outstanding loans under the Corporation Revolving Credit Facility at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary repayments made by PG&E Corporation will not reduce the commitments under the Corporation Revolving Credit Facility.

On the Effective Date, PG&E Corporation repaid and terminated (i) $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 and (ii) $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.

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 PG&E AR Facility, LLC (the “SPV”), a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility will sell 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, will obtain 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 will 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.

The Utility closed the Receivables Securitization Program on October 5, 2020. As of October 27, 2020, the Utility has obtained $1 billion in loans under the Receivables Securitization Program and the proceeds were primarily used to reduce borrowings outstanding on the Utility Revolving Credit Facility. In general, the proceeds from the sale of the accounts receivable will be 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.

Although PG&E AR Facility, LLC is a wholly owned consolidated subsidiary of the Utility, PG&E AR Facility, LLC is legally separate from the Utility. The assets of PG&E AR Facility, LLC (including the accounts receivables) 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 will be accounted for as a secured financing. When amounts are received from the Lenders, the pledged receivables and the corresponding debt will be included in Accounts receivable and Short-term borrowings, respectively, on the Condensed Consolidated Balance Sheets.

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 among the Escrow Agent and the Utility. On July 1, 2020, the net proceeds 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 (the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt, as described in the table below.

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 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.

In addition, on July 1, 2020, the Utility obtained a $1.5 billion 18-month secured term loan under a term loan credit agreement. For more information, see “Credit Facilities” discussion above.

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”) with JPM, and other lenders from time to time party thereto (collectively, the “Lenders”), JPM, as Administrative Agent and as Collateral Agent. The proceeds of the Term Loan 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 among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation and subsequently released from escrow on the Effective Date pursuant to the Plan.

In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the Term Loan by $6.875 million on the last day of each quarter. The Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The Term Loan bears interest based, at PG&E Corporation’s election, on (1) LIBOR (but in no event less than 1.0%) plus an applicable margin or (2) ABR (but in no event less than 2.0%) plus an applicable margin. ABR will equal the highest of the following: the prime rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus 1.0%. The applicable margin for LIBOR loans is 4.5% and the applicable margin for ABR loans is 3.5%. PG&E Corporation may prepay the Term Loan in whole, at any time, and in part, from time to time, without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans; provided, however, that any voluntary prepayment, refinancing or repricing of the Term Loan in connection with certain repricing transactions that occur on or prior to the first anniversary of the Effective Date shall be subject to a prepayment premium of 1.0% of the principal amount of the term loans so prepaid, refinanced or repriced.

The Term Loan Agreement includes usual and customary covenants for loan agreements of this type, including covenants limiting: (1) liens, (2) mergers, (3) sales of all or substantially all of PG&E Corporation’s assets, and (4) sale and leaseback transactions. In addition, the Term Loan Agreement requires that PG&E Corporation maintain ownership, either directly or indirectly, through one or more subsidiaries, of at least 100% of the outstanding common stock of the Utility.

In the event of a default by PG&E Corporation under the Term Loan Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the Administrative Agent may, with the consent of the required Lenders (or upon the request of the required Lenders, shall), declare the amounts outstanding under the Term Loan Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Term Loan Agreement become payable immediately.

On the Effective Date, the obligations under the Term Loan Agreement became secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. On July 1, 2020, the net proceeds from the Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.

Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (the “2030 Notes,” and together with the 2028 Notes, the “Notes”). The proceeds of the Notes 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 among the Escrow Agent and PG&E Corporation. Prior to July 1, 2023, in the case of the 2028 Notes, and prior to July 1, 2025, in the case of the 2030 Notes, (i) PG&E Corporation may redeem all or part of the Notes of the applicable series, on any one or more occasions at a redemption price equal to 100% of the principal amount of Notes of such series to be redeemed, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the redemption date or (ii) PG&E Corporation may redeem up to 40% of the aggregate principal amount of the Notes of the applicable series on any one or more occasions at certain specified redemption prices with the net cash proceeds from certain equity offerings. On or after July 1, 2023, in the case of the 2028 Notes, and July 1, 2025, in the case of the 2030 Notes, PG&E Corporation may redeem the Notes of a series at certain specified redemption prices, plus accrued and unpaid interest thereon, if any, to but not including, the applicable redemption date.

On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Corporation and the Utility in accordance with the terms and conditions contained in the Plan. The Notes are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.

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

At ~~March 31,~~September 30, 2020, the Utility’s outstanding derivative balances were as follows:

At December 31, 2019, the Utility’s outstanding derivative balances were as follows:

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. ~~During the first quarter of 2019,~~Upon emergence from Chapter 11, multiple credit ~~rating~~ agencies ~~downgraded~~continue to rate the ~~Utility’s credit ratings~~Utility below investment grade, which ~~resulted~~results in the Utility posting additional collateral. As of ~~March 31,~~September 30, 2020, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

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

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

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

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019.

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

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

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

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

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

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

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

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

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

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 8 above.)

The following table presents the reconciliation for Level 3 instruments for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019:

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable; short-term borrowings; accounts payable; and customer deposits approximate their carrying values at ~~March 31,~~September 30, 2020 and December 31, 2019, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

The following table provides a summary of equity securities and available-for-sale debt securities:

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

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

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

~~Third-Party~~During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims

~~There were 0 charges for~~According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the ~~three months ended March 31, 2020. At March 31, 2020 and December 31, 2019,~~city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s ~~Consolidated Balance Sheets include~~service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire.

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated ~~liabilities~~8,900 structures. The 2017 Northern California wildfires resulted in ~~respect~~44 fatalities.

PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of ~~total~~wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims have been satisfied and discharged in accordance with the Plan, as described below.

Pre-petition wildfire-related claims ~~of $25.5 billion. The aggregate liability of $25.5 billion for claims in connection~~on the Condensed Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte ~~fire is comprised of (i) $11 billion for subrogated insurance claimholders~~fire.

On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477.0 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Equity Units Underwriters exercising their option to purchase 1.45 million additional Equity Units, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with the Fire Victim Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.”

On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation ~~RSA, plus (ii)~~Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for ~~expected~~ professional fees ~~for professionals retained by subrogated insurance claimholders~~was extinguished in the third quarter of 2020.

On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be ~~reimbursed~~used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims has been satisfied, released and discharged in the third quarter of 2020.

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the ~~Subrogation RSA, plus (iii) $1 billion for~~Plan in order to fully and finally settle and discharge such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”).

The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with ~~respect~~the defense or resolution of claims against the Supporting Public Entities by third parties relating to ~~their Public Entity Wildfire~~the wildfires noted above (“Third Party Claims”).

These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date.

On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the ~~PSAs, plus (iv) $13.5 billion~~Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for ~~all other wildfire-related claims, including individual wildfire claimholders (including those~~professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date.

On December 6, 2019, PG&E Corporation and ~~underinsured property losses) and clean-up and fire suppression costs, pursuant to~~the Utility entered into the TCC RSA. The ~~aggregate liability~~TCC RSA provides for, among other things, a combination of ~~$25.5~~cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims will consist of (a) $5.4 billion ~~for claims~~in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $650 million to be paid in cash on or before January 15, 2021 and (ii) the remaining balance of $1.35 billion to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of a tax benefit payment agreement to be entered into between the Fire Victim Trust and the reorganized Utility, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the ~~2018 Camp~~monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also includes (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the ~~2015 Butte~~2018 Camp fire ~~corresponds to PG&E Corporation’s and~~(together, the ~~Utility’s best estimate of probable losses and is subject to change based on additional information, including the other factors discussed below.~~

~~The aggregate liability~~Pursuant to further discussions with claimants relating to the Ghost Ship fire, certain provisions of ~~$25.5 billion for~~the TCC RSA were superseded by the terms of the Plan, and accordingly the above description of the TCC RSA has been revised to reflect the fact that claims ~~in connection with~~arising out of the ~~2018 Camp,~~Ghost Ship fire will be resolved separately from the ~~2017 Northern California wildfires~~TCC RSA.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the ~~2015 Butte fire represents PG&E Corporation’s and~~funding to be made pursuant to the ~~Utility’s best estimate of probable losses and is subject to change based on additional information. Notwithstanding the entry into the PSAs, the Subrogation~~TCC RSA and the ~~TCC RSA, there are a number of unknown facts and legal considerations that may impact~~Plan were made on the amount of any potential liability, including whether any termination events are triggered under these agreements, whether the classification and treatment of claims in the Plan is successfully challenged by claimholders who are not party to a settlement agreement, whether the requisite number of impaired claimholders vote to approve the Plan in the Chapter 11 Cases, whether any fines or penalties are treated as Fire Claims as provided in the Plan and whether a plan of reorganization incorporating the terms of those settlements is confirmed. (See “Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires” above for a summary of material termination rights under the PSAs, the Subrogation RSA and the TCC RSA.) Many of these factors are beyond the control of PG&E Corporation and the Utility. For example, notwithstanding the TCC RSA, the TCC filed a motion in the Bankruptcy Court on April 6, 2020 seeking approval of a letter from the TCC to individual holders of wildfire-related claims requesting that they withhold their votes in favor of the Plan until the Utility provides supplemental disclosure with respect to the Plan and certain issues relating to the value of the stock to be distributed to the Fire Victim Trust (which the Bankruptcy Court denied). The Bankruptcy Court issued an order denying the TCC’s motion on April 7, 2020. If one or more of these settlement agreements is terminated or if one or more classes of impaired claimholders fail to approve the Plan, PG&E Corporation’s and the Utility’s aggregate liability related to the 2018 Camp fire and 2017 Northern California wildfires (and in certain cases, other pre-petition fires) could substantially exceed $25.5 billion. In addition, if these agreements were terminated, regardless of the ultimate determination of PG&E Corporation’s and the Utility’s liability, such termination would be expected to result in additional delay and expense in the Chapter 11 Cases.

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported 0 fatalities and 4 first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, 1 commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.

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~~The~~On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade ~~fire is under investigation by~~fire. Cal Fire has 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 ~~CPUC, and PG&E Corporation and~~Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility ~~are cooperating~~entered into a tolling agreement with ~~those investigations.~~ the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021.

PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties. ~~There are a number of unknown facts surrounding~~

Potential liabilities related to the Kincade fire depend on various factors, including but not limited to the cause of the ~~2019~~fire, contributing causes of the fire (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, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the Kincade fire, and ~~accordingly,~~ the ~~cause~~doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the ~~2019 Kincade fire remains uncertain.~~application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.)

~~Based on~~In light of the ~~facts~~current state of the law concerning inverse condemnation and ~~circumstances~~the information currently available to PG&E Corporation and the Utility, ~~as of the date of this filing,~~ including the information contained in the electric incident ~~report~~reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is ~~reasonably possible~~probable that they will incur a loss in connection with the 2019 Kincade fire. If PG&E Corporation and the Utility ~~were~~recorded a charge in the amount of $600 million for the six months ended June 30, 2020 (before available insurance). Based on additional facts and circumstances available to ~~incur a loss in respect~~the Utility as of the ~~2019 Kincade fire,~~date of this filing, PG&E Corporation and the Utility ~~estimate that~~recorded an additional charge for potential losses in connection with the 2019 Kincade fire in the amount of ~~such loss could exceed $600~~$25 million for the three months ended September 30, 2020.

The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance)~~. This amount~~ corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of ~~reasonably possible~~ losses and is subject to change based on additional information. The ~~$600~~$625 million estimate ~~of the lower end of the range of reasonably possible losses~~ does not include, among other things, (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state ~~county and local government entities or~~ agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable.

The $600 million estimate of the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses from the end of the prior quarter was based primarily on publicly available information and the Utility had not received significant data regarding actual claimed losses from potential claimants. Since that time, the Utility has received certain information from potential claimants, including certain information received from holders of certain insurance subrogation claims, leading to an increase in such estimate of the lower end. The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in additional changes to the accrual depending on the information provided.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than ~~$600~~$625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of potential damages.

The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change.

InThe Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the ~~future,~~Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is ~~possible~~deemed probable that ~~facts could emerge that lead~~ recovery will occur, and the Utility can reasonably estimate the amount or its range. As of September 30, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

PG&E Corporation and the Utility have received and are responding to ~~believe that a loss~~data requests from the SED relating to the Kincade fire. The Sonoma County District Attorney’s Office is ~~probable, resulting in~~currently investigating the ~~accrual~~fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete.

As of ~~a liability at that time,~~October 28, 2020, PG&E Corporation and the ~~amount~~Utility are aware of ~~which could be significant and may exceed the foregoing estimate~~16 complaints on behalf of ~~the lower end of the range of reasonably possible losses. For the reasons discussed above,~~approximately 377 plaintiffs related to the 2019 Kincade fire and expects that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma 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 transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

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

According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported 4 fatalities and 1 injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed.

On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that:

The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information contained in the electric incident report and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is reasonably possible that they will incur a loss in connection with the 2020 Zogg fire. However, due to the limited amount of time that has elapsed since the start of the 2020 Zogg fire, the preliminary stages of the investigations, and the uncertainty as to the extent and magnitude of potential losses, PG&E Corporation and the Utility cannot reasonably estimate the amount or range of such possible loss at this time.

While the cause of the 2020 Zogg fire remains under investigation and there are a number of unknown facts surrounding the cause of the 2020 Zogg fire, the Utility could be subject to significant liability in connection with this fire. If such liability were to exceed insurance coverage, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash ~~flows, as well as on the bankruptcy timing and process and the ability of the Utility to participate in the Wildfire Fund.~~flows.

As of October 28, 2020, PG&E Corporation and the Utility are aware of 1 complaint on behalf of approximately 6 plaintiffs that may be related to the 2020 Zogg fire and expect that they may receive further such complaints. The 1 complaint filed thus far has, as of October 28, 2020, not yet been served on PG&E Corporation or the Utility, and PG&E Corporation and the Utility have ~~received and are responding~~not yet had the opportunity to data requests from the CPUC’s SED relating to the Kincade fire. Various other entities, including law enforcement agencies, may also be investigating the fire. It is uncertain when the investigations will be complete.review it.

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.

As of March 31, 2020, PG&E Corporation and the Utility recorded charges of $344 million, related to the portion of the $403 million in disallowed capital that had been spent through March 31, 2020 and, in 2020, expects to record $59 million related to capital expenditures listed in the table above. In addition, PG&E Corporation and Utility recorded charges of approximately $71 million related to vegetation management and catastrophic event expense costs that were previously determined to be probable of recovery and expects to record an additional $19 million in expenses later in 2020.

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 ~~could consider and vote on the POD and~~approved the Decision Different ~~as early as~~ on May 7, 2020.

The settlement agreement, as modified by the Decision Different, ~~will become~~became effective upon: (i) approval by the CPUC in ~~a written decision,~~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 ~~a chapter 11 plan of reorganization for~~the Plan.

As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility ~~approving~~has recorded charges of $80 million as of September 30, 2020 and intend to record the ~~implementation~~remaining charges of $118 million in fourth quarter of 2020 and 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. The CPUC may accept, reject or propose alternative terms to~~agreement, as modified. On June 23, 2020, the ~~settlement agreement~~Utility and ~~Decision Different, including imposing additional penalties on~~CUE filed a joint response opposing the ~~Utility.~~

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, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 went into effect on May 1, 2019.

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, FERC issued an order that affirmed in part and reversed in part the initial decision. The ~~Utility expects~~order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning FERC’s revised ROE methodology adopted in 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 ~~issue a~~earn on electric transmission investments. 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 inreduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the ~~TO18~~ rate case period. Finally, the order upheld the initial decision’s rejection of 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 ~~2020, however,~~an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the ~~timing of that decision is uncertain, and it will likely be the subject of requests for rehearing and appeal.~~Utility’s direct assignment method.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by 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.

On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing of its TO20 formula rate case, subject to hearings and refund, and established May 1, 2019, as the ~~effective date~~Effective Date for rate changes. The FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. On March 31, 2020, the Utility filed a partial settlement of TO20 resolving certain issues related to the formula rate but leaving several issues including return on equity, capital structure, and depreciation rates for further settlement discussions or hearing. FERC approved the Partial Settlement on August 17, 2020. On October 15, 2020, the Utility filed a settlement with 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. 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 required 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 FERC. The settlement also provides that the Utility will make supplemental filings in two FERC dockets addressing the calculation of the AFUDC, effective May 1, 2019, to reflect the terms of the settlement. The two AFUDC dockets have not been consolidated with the Formula Rate Proceedings but include capital structure issues addressed by the settlement.

The Utility is unable to predict the timing or outcome of FERC’s decisions in the TO18 and TO19 ~~proceedings or the timing or outcome of the TO20 proceeding.~~

PG&E Corporation and the Utility are subject to various claims ~~lawsuits,~~ and ~~regulatory proceedings~~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 ~~$117~~$167 million and $116 million at ~~March 31,~~September 30, 2020 and December 31, 2019, ~~respectively,~~respectively. These amounts were included in LSTC at December 31, 2019 and were included in ~~LSTC.~~Other current liabilities at September 30, 2020. 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.

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and 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.

On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus 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, plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. Plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. Plaintiff filed a designation of the record and statement of the issues on April 20, 2020, and the Utility ~~will have~~had until May 4, 2020, 14 days thereafter, to file a designation of any additional items.

On June 8, 2020, plaintiff filed its opening brief. The Utility filed its opposition brief on July 6, 2020. Plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. The court has not yet ruled on plaintiff’s request for oral argument.

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

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 ~~an audit~~a review of reasonableness to be conducted, or overseen, by the CPUC ~~staff, with~~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 ~~possibility that~~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 ~~may seek~~filed an application seeking recovery inof revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a ~~future~~scoping memo establishing the scope and schedule for the proceeding. ~~Additional charges may be required~~The scoping memo requires the Utility to provide supplemental testimony on January 20, 2021 addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the ~~future based on~~fourth quarter of 2021.

The Utility is unable to determine the timing and outcome of ~~the CPUC’s audit of 2011 through 2014 capital spending. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income.~~this upcoming proceeding.

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at ~~March 31,~~September 30, 2020, 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. At ~~March 31,~~September 30, 2020, the Utility expected to recover ~~$1,029~~$1,003 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

For more information, see remediation site descriptions below and see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

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.

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as ~~$216~~$221 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

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. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as ~~$129~~$137 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 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 ~~$539~~$492 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

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 ~~$78~~$64 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

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 ~~$80~~$40 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.

The Utility maintains multiple insurance policies through NEIL and European Mutual Association for Nuclear Insurance, covering nuclear or non-nuclear events at the Utility’s 2 nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. 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, ~~as of the policy renewal on April 1, 2020,~~ the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million. If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 ~~million, as of the policy renewal on April 1, 2020.~~million. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of ~~March 31,~~September 30, 2020, it is reasonably possible that unrecognized tax benefits will decrease by approximately ~~$40~~$30 million within the next 12 months.

As of the date of this report, PG&E Corporation ~~does~~did not believe that ~~the Chapter 11 Cases resulted in~~it had undergone an ownership change, and consequently, its net operating loss ~~of or limitation on the utilization of any~~carryforwards and other tax attributes are not limited by Section 382 of the ~~tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards during the pendency of the Chapter 11 Cases.~~Internal Revenue Code.

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility expect to be able to defer the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022.

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

83See “Ownership Restrictions in PG&E Corporation’s Amended Articles” in Note 6 for information on the possible election to treat the Fire Victim Trust as a “grantor trust” for federal income tax purposes.

PG&E Corporation’s net ~~income (loss)~~loss primarily consists of income taxes, interest ~~income on cash held, interest~~ expense on long-term debt, reorganization items, net, including approximately $1.5 billion in expense related to the Backstop Commitment premium and ~~reorganization items.~~Additional Backstop Premium Shares in the second quarter of 2020, which is not deductible for tax purposes.

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019. The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized (such as energy procurement costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings.

91

The following discussion presents the Utility’s operating results for the three and nine months ended ~~March 31,~~September 30, 2020 and 2019, focusing on revenues and expenses that impacted earnings for these periods.

The Utility’s electric and natural gas operating revenues that impacted earnings increased by ~~$312~~$342 million, or 12%, and $1,126 million, or 14%, in the three and nine months ended ~~March 31,~~September 30, 2020, respectively, compared to the same ~~period~~periods in 2019, primarily due to additional revenues recorded pursuant to the ~~pending~~ TO20 rate case and cost recovery of capital expenditures related to the 2011-2014 GT&S rate case. In addition, the portion of authorized revenues related to interest expense on pre-petition debt was deferred as a regulatory liability and reduced revenues that impacted earnings during the three and nine months ended September 30, 2019 with no comparable impacts in the same periods in 2020.

The Utility’s operating and maintenance expenses that impacted earnings ~~decreased~~increased by ~~$231~~$61 million or ~~14%,~~3% in the three months ended ~~March 31,~~September 30, 2020, compared to the same period in 2019, primarily due to $75 million in previously deferred CEMA costs recorded in conjunction with interim rate relief (see “2018 CEMA Application” below) in the three months ended September 30, 2020, with no comparable costs in the same period in 2019. In addition, bad debt expense increased in the three months ended September 30, 2020, as compared to the same period in 2019 as a result of the COVID-19 pandemic. The Utility also experienced increased labor and contract costs in the three months ended September 30, 2020, compared to the same period in 2019. These increases were partially offset by $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case incurred in the three months ended September 30, 2019, with no corresponding charges during the same period in 2020.

The Utility’s operating and maintenance expenses that impacted earnings decreased by $134 million, or 3%, in the nine months ended September 30, 2020, compared to the same period in 2019, primarily due to a ~~decrease of $198 million~~reduction in clean-up costs related to ~~electric asset inspections costs. Additionally,~~the 2018 Camp fire of $237 million (the Utility recorded $265 million of clean-up and repair costs relating to the 2018 Camp fire ~~decreased~~incurred in the nine months ended September 30, 2019, compared to $28 million in restoration and rebuild costs related to the 2018 Camp fire in the same period in 2020). Additionally, the Utility recorded $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case in the nine months ended September 30, 2019, with no corresponding charges during the same period in 2020. These decreases were partially offset by ~~$166~~$225 million in previously deferred CEMA costs recorded in conjunction with interim rate relief (see “2018 CEMA Application” below) in the nine months ended September 30, 2020, with no comparable costs in the same period in 2019. In addition, bad debt expense increased in the nine months ended September 30, 2020, as compared to the same period in 2019 ~~(the~~as a result of the COVID-19 pandemic. Finally, the Utility ~~recorded $13~~incurred $35 million in the three months ended March 31, 2020 for clean-up and repair costs related to the 2018 Camp fire, as compared to $179 million in same period in 2019). These decreases were partially offset by $43 million forof clean-up and repair costs relating to the 2019 Kincade fire incurred in the nine months ended September 30, 2020, with no comparable charges in the same period in 2019.

Costs related to wildfires that impacted earnings decreased by $2.5 billion, or 99%, in the three months ended ~~March 31,~~September 30, 2020, compared to the same period in 2019. The Utility recognized pre-tax charges of $526 million and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three months ended September 30, 2019, compared to $25 million in pre-tax charges to the 2019 Kincade fire in the three months ended September 30, 2020.

92Costs related to wildfires that impacted earnings decreased by $6.3 billion, or 97%, in the nine months ended September 30, 2020, compared to the same period in 2019. The Utility recognized pre-tax charges of $625 million related to the 2019 Kincade fire, partially offset by $430 million in insurance recoveries for the nine months ended September 30, 2020, with no corresponding charges during the same period in 2019. Additionally, the Utility recognized pre-tax charges of $2.4 billion and $4.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the nine months ended September 30, 2019, with no corresponding charges during the same period in 2020.

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs. See below for more information.

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred such as pension contributions and public purpose programs costs. If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.

The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date of the accompanying Condensed Consolidated Financial Statements.

As of and subsequent to the Effective Date, the Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s exit from Chapter 11.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility, depends on the level of cash on hand, cash distributions received from the Utility, and PG&E Corporation’s access to the capital and credit markets.

In 2019, as a result of the initiation of the Chapter 11 Cases, each of Moody’s, Fitch, and S&P withdrew its credit ratings for PG&E Corporation and the Utility. As a result of PG&E Corporation’s and the Utility’s credit ratings ceasing to be rated at investment grade, the Utility was required to post collateral under certain of its commodity purchase agreements and certain other obligations. On June 15, 2020, the agencies re-commenced rating the Utility and PG&E Corporation. The Utility and PG&E Corporation were assigned Ba2, BB, and BB- as their issuer credit ratings by Moody’s, Fitch, and S&P, respectively. Additionally, Moody’s assigned a B1 rating to PG&E Corporation’s Senior Secured debt, a Baa3 rating to the Utility’s Senior Secured debt, and a B1 rating to the Utility’s preferred stock. Fitch assigned a BB rating to PG&E Corporation’s Senior Secured debt, a BBB- rating to the Utility’s Senior Secured debt, and a BB rating to the Utility’s preferred stock. Lastly, S&P assigned a BB- and BBB- rating to PG&E Corporation’s and the Utility’s Senior Secured debt, respectively.

The outbreak of COVID-19 and the resulting economic conditions and government orders have and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have and will continue to impact the Utility for an indeterminate period of time. Although the Utility is seeking regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance that any relief is forthcoming or that, if any relief measures are implemented, the timing that any such relief would impact the Utility. On April 16, 2020, the CPUC approved a resolution that authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the customer protections described within the resolution. ~~The~~On May 1, 2020, the Utility ~~must file a Tier 2 Advice Letter~~filed an advice letter with the CPUC, ~~no later than May 1, 2020,~~ describing all reasonable and necessary actions to implement emergency customer protections through April 16, ~~2021.~~2021, which was subsequently updated on June 2, 2020, and July 15, 2020, to modify and clarify the filing based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter. (See “Emergency Authorization and ~~Order~~Resolution Directing Utilities to Implement Emergency Customer COVID-19 Protections” below for more information.)

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.

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 were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.

On July 23, 2020, PG&E Corporation sent a notice of ~~Pre-Petition Debt Obligations~~termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. During the nine months ended September 30, 2020, 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 common stock in the Common Stock Offering, (ii) 342.1 million shares of common stock pursuant to the Investment Agreement, (iii) forward stock purchase contracts to the Backstop Parties pursuant to the Forward Stock Purchase Agreement and (iv) 14.5 million Equity Units in the Equity Unit Offering.

The ~~commencement~~prepaid forward stock purchase contract portion of the ~~Chapter 11 Cases constituted an event of default or termination event with respect to,~~Equity Units issued in July and ~~caused an automatic and immediate acceleration~~August 2020 represents the right of the ~~Accelerated Direct Financial Obligations. Accordingly,~~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 was 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 ~~a result~~provided therein. The settlement date of the commencement of the Chapter 11 Cases, the principal amount of the Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case of certain indebtedness, premium, if any, thereon, immediately became due and payable. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and arepurchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the ~~applicable provisions of~~purchase contracts. Such gross proceeds were used to fund distributions under the ~~Bankruptcy Code and orders of~~Plan.

For the ~~Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and~~nine months ended September 30, 2020, PG&E ~~Corporation’s term loan facility, as well as short-term borrowings under~~Corporation made equity contributions to the Utility of $12.9 billion in cash and 477 million shares of PG&E ~~Corporation’s and~~Corporation common stock. Such shares were transferred to the ~~Utility’s revolving credit facilities and the Utility’s term loan facility disclosed in~~Fire Victim Trust.

For more information, see Note ~~5 of~~6 to the Notes to the Condensed Consolidated Financial Statements in Item 1.

On ~~October 11, 2019,~~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 among 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 ~~and the Utility entered into the Debt Commitment Letters~~in accordance with the Commitment Parties, which were subsequently amended on November 18, 2019, December 20, 2019, January 30, 2020, February 14, 2020 and February 28, 2020, pursuant to which the Commitment Parties committed to provide $10.825 billion in bridge financing in the form of (a) a $5.825 billion senior secured bridge loan facility (the “OpCo Facility”) with the Utility or any domestic entity formed to hold all of the assets of the Utility upon emergence from bankruptcy as borrower thereunder and (b) a $5 billion senior unsecured bridge loan facility (together with the OpCo Facility, the “Facilities”) with PG&E Corporation or any domestic entity formed to hold all of the assets of PG&E Corporation upon emergence from bankruptcy as borrower thereunder, subject to the terms and conditions ~~set forth therein. The commitments under~~contained in the ~~Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier~~Plan.

On the Effective Date, pursuant to the ~~termination rights set forth~~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 ~~Debt Commitment Letters. PG&E Corporation~~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 ~~will pay customary fees~~Reinstated Senior Notes are secured by a first lien, subject to permitted liens, on substantially all of the Utility’s real property and expenses in connection with obtaining the Facilities. If the entire $10.825 billion of bridge commitments remain outstanding as of June 30, 2020, the aggregate fees payable (including commitment fees and ticking fees, but excluding any feescertain tangible property related to its facilities. The Mortgage Bonds, the ~~funding of the Facilities) by PG&E Corporation~~New Mortgage Bonds and the Utility ~~would be approximately $75 million.~~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.

~~In connection with~~On the ~~anticipated funding for~~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 ~~anticipated amount of debt~~Utility Funded Debt were cancelled and ~~equity to be used for funding thereunder, on February 14, 2020,~~ the ~~Debt Commitment Letters~~applicable agreements governing such obligations were amended to, among other things, (1) adjust the maximum amount of any roll-over, “take-back” or reinstated debt permitted under the Facilities from $30.0 billion to $33.35 billion at the Utility and from $7.0 billion to $5.0 billion at PG&E Corporation, (2) reduce the amount of proceeds from the issuance of equity that PG&E Corporation has to receive as a condition to funding from $12.0 billion to $9.0 billion, and (3) increase the amount of proceeds from the issuance of debt securities or other debt for borrowed money as a condition to funding from $2.0 billion at PG&E Corporation to $6.0 billion at the Utility.terminated.

In lieu of entering into the Facilities, PG&E Corporation and the Utility intend to obtain permanent financing on or prior to emergence from bankruptcy in the form of bank facilities, debt securities or a combination of the foregoing. (See “Anticipated Sources and Uses for Chapter 11 Emergence and Related Financings” below and "Plan of Reorganization, RSAs, Equity Backstop Commitments and Debt Commitment Letters"For more information, see “Long-Term Debt” in Note ~~2 of~~5 to the Notes to the Condensed Consolidated Financial Statements in Item 1.)

On ~~October~~June 23, ~~2019,~~2020, PG&E Corporation obtained a $2.75 billion secured term loan under a term loan credit agreement (“the “Term Loan Agreement”). The Term Loan matures on the date that is five years after June 23, 2020, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The proceeds of the Term Loan 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 among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the 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 Term Loan by $6.875 million on the last day of each quarter.

Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (collectively, the “Notes”). The proceeds of the Notes 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 amount the Escrow Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility ~~filed a motion~~in accordance with the Bankruptcy Court seeking approval of the Debt Commitment Letters and certain related matters. On March 16, 2020, the Bankruptcy Court approved the Debt Commitment Letters (as amended through February 28, 2020).

For more information, see “Long-Term Debt” in Note ~~2 of~~5 to the Notes to the Condensed Consolidated Financial Statements in Item 1.~~) On March 16, 2020, the Bankruptcy Court approved the Commitment Letters (as amended through March 6, 2020).~~

On July 1, 2020, the Utility ~~expect that~~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 Facility has tenor of three years, subject to two one-year extension options. The proceeds from the ~~funding for~~Utility Revolving Credit Facility were used in part to fund transactions contemplated under the Plan ~~will consist~~and are intended to finance working capital needs, capital expenditures and other general corporate purposes of ~~both new debt and equity for both PG&E Corporation and~~ the Utility ~~as well as other sources of funding totaling approximately $58 billion. For additional information, see the 2019 Form 10-K.~~and its subsidiaries.

In addition, on ~~April~~July 1, 2020, the Utility obtained a $3.0 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 Loan 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 for the Utility 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The proceeds from the Utility Term Loan Credit Facility were used to fund transactions contemplated under the Plan.

At September 30, 2020, the Utility ~~filed an application~~had fully drawn on its $3.0 billion term loan credit facilities and had $1.7 billion available under its $3.5 billion revolving credit facility.

For more information, see “Credit Facilities” in Note 5 to the Condensed Consolidated Financial Statements in Item 1.

On July 1, 2020, PG&E Corporation entered into a $500 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 the Corporation Revolving Credit Facility 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 (i) $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 and (ii) $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the ~~CPUC seeking authorization for a post-emergence securitization transaction. (For~~Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.

At September 30, 2020, PG&E Corporation did not have any borrowings outstanding under its revolving credit facility.

For more information, ~~regarding~~see “Credit Facilities” in Note 5 to the ~~application, see “Regulatory Matters” below.~~Condensed Consolidated Financial Statements in Item 1.

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 PG&E AR Facility, LLC (the “SPV”), a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility will sell 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, will obtain 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 will 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.

The Utility closed the Receivables Securitization Program on October 5, 2020. As of October 27, 2020, the Utility has obtained $1 billion in loans under the Receivables Securitization Program and the proceeds were primarily used to reduce borrowings outstanding on the Utility Revolving Credit Facility. In general, the proceeds from the sale of the accounts receivable will be 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.

Although PG&E AR Facility, LLC is a wholly owned subsidiary of the Utility whose financial results are consolidated for accounting purposes with the Utility, PG&E AR Facility, LLC is legally separate from the Utility. The assets of PG&E AR Facility, LLC (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and its accounts receivable are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program will be accounted for as a secured financing. When amounts are received from the Lenders, the pledged receivables and the corresponding debt will be included in Accounts receivable and Short-term borrowings, respectively, on the Condensed Consolidated Balance Sheets.

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, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including foregoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s Wildfire Mitigation Plan.

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

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

Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. The Utility’s preferred stock is cumulative and any dividends in arrears must be paid before the Utility may pay any common stock dividends. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s exit from Chapter 11.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of September 30, 2020, it is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.

For more information on dividends, see “Dividends” in Note 6 to the Condensed Consolidated Financial Statements.

The PG&E Corporation consolidated cash flows consist primarily of cash flows related to the Utility, which are discussed in the “Utility Cash Flows” section below.

There was no material change to PG&E Corporation’s standalone cash flows from operating and investing activities for the periods presented.

PG&E Corporation’s standalone cash flows from financing activities decreased by $205 million during the nine months ended September 30, 2020, as compared to the same period in 2019. This decrease is due to PG&E Corporation’s cash equity contribution to the Utility of approximately $13 billion and long-term debt repayments of $650 million, with no similar payments made in 2019. This decrease is partially offset by cash received from long-term debt issuances of $4.7 billion, with no similar issuances in 2019, and cash received from common stock and equity units issued of $8.9 billion, as compared to common stock issuances of $85 million in 2019.

Cash provided by or used in financing activities is driven by PG&E Corporation’s standalone financing needs, which depends on the level of cash on hand, cash distributions received from the Utility, access to the capital and credit markets, and the maturity date or prepayment of existing debt instruments.

The Utility’s cash flows were as follows:

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 the ~~three~~nine months ended ~~March 31,~~September 30, 2020, net cash provided by operating activities decreased by ~~$662 million~~$23.2 billion compared to the same period in 2019. This decrease was ~~due to an increase in vendor payments in 2020 that were not paid during the first quarter of 2019~~primarily due to the ~~automatic stay as~~payment of $18.8 billion in satisfaction of pre-petition wildfire-related claims (including claims associated with the ~~Petition Date,~~2018 Camp fire, the 2017 Northern California wildfires, and ~~a reduction~~the 2015 Butte fire), and initial and first annual contributions made to the Wildfire Fund of $5.0 billion, with no similar payments made in ~~cash receipts from customers as a result of the economic impacts of the COVID-19 pandemic.~~2019.

The Utility will continue to operate its business as a debtor in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. Future cash flow from operating activities will be affected by various ~~ongoing activities,~~factors, including:

Net cash used in investing activities increased by ~~$408 million~~$1.3 billion during the ~~three~~nine months ended ~~March 31,~~September 30, 2020 as compared to the same period in ~~2019.~~2019 partially due to the payment of pre-petition vendor payables for capital expenditures as a result of emerging from Chapter 11. 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.

Cash paid by the Utility for capital expenditures was approximately $6.3 billion in 2019. 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 approximately $7.5 billion in capital expenditures in ~~2020.~~2020 and between $7.6 billion and $8.2 billion in 2021. Additionally, future cash flows from investing activities will be impacted by the timing of and amount received from the sale of the SFGO.

Net cash provided by financing activities increased by ~~$245 million~~$22.6 billion during the ~~three~~nine months ended ~~March 31,~~September 30, 2020 as compared to the same period in 2019. This increase was primarily due to ~~an additional $150 million~~PG&E Corporation making a cash equity contribution to the Utility of ~~borrowings under~~approximately $13 billion and due to the ~~DIP Facilities and an approximately $90 million reduction~~Utility receiving $8.8 billion in ~~amounts paid for DIP credit facility debt~~proceeds from the issuance ~~costs~~of first mortgage bonds, with no similar activity in ~~2020 as compared to~~ 2019. Additionally, the Utility ~~paid $30~~had net borrowings of $940 million ~~in bridge~~under its revolving credit facility ~~financing fees in~~during the nine months ended September 30, 2020, with no similar ~~amount~~activity in ~~2019.~~2019 due to the Utility entering into the revolving credit agreement on July 1, 2020.

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 of existing debt instruments.

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 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and matters described in “Part II. Other Information, Item 1. Legal Proceedings” below. 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. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2019 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.”

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count 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.

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

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On April 29, 2020, the court issued an order imposing new conditions of ~~probation that would require the Utility, among other things, to:~~probation.

•~~employ,~~On May 13, 2020, the Utility filed motions with the court asking that it reconsider the April 29, 2020 order and issue a stay on ~~its own payroll, “a sufficient number of inspectors~~implementing the new conditions until it has had a chance to ~~manage~~rule on the outsourced tree-trimming work,” including pre-inspectors to “identify trees and limbs in violation of California clearance laws that require trimming” and post-inspectors to “spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed,” and submit a detailed plan to carry out this requirement by May 28, 2020;Utility’s request for reconsideration.

•~~“keep records identifying~~On May 14, 2020, the ~~age of every item of equipment~~court issued an order staying the April 29, 2020 order and ordering certain other procedural actions. On June 24, 2020, after a hearing on ~~every transmission tower and line,” ensuring that “every part [has]~~the Utility’s motion for reconsideration, the Utility filed a ~~recorded date of installation” and “[i]f the age of a part is unknown, [] conduct research and estimate the year of installation;”~~

On June 17, 2020, the court issued an order requiring the Utility to respond to each statement in the Butte County District Attorney’s report filed in the criminal prosecution of the Utility in connection with the 2018 Camp Fire entitled “People’s Statement of Factual Basis in Support of the Pleas and Sentencing Statement” that the Utility denies is true and provide the reason for the denial. The Utility filed its response on July 1, 2020.

On July 21, 2020, the court issued an order requiring the Utility, the Monitor, and the Department of Justice to clarify certain aspects of the proposed additional conditions of probation set forth in the June 24, 2020 joint submission. The Utility filed its response on July 28, 2020.

On July 24, 2020, the Utility submitted a ~~material effect~~report to the court to update the court on the condition of the Utility’s ~~financial condition, results~~Caribou-Palermo 115 kV Transmission Line (the “Caribou-Palermo Line”). The Utility indicated in its report that energized lines in the same vicinity as the Utility’s de-energized Caribou-Palermo Line may have the potential to induce voltage and current onto the Caribou-Palermo line, despite the Caribou-Palermo line’s de-energized state. The Utility further indicated in its report the steps it has taken to mitigate this risk and additional steps that it will be taking in the future. The Utility also has notified the Monitor, its probation officer, the CPUC and the Butte County District Attorney of the facts and mitigation efforts set forth in its report.

On August 7, 2020, the court entered an order withdrawing the conditions of probation proposed in its April 29, 2020 order and adopting the new conditions jointly proposed by the Utility, the Monitor, and the Department of Justice on June 24, 2020. Among other things, these conditions require the Utility to staff an in-house vegetation inspection manager and approximately 30 additional field inspectors to oversee vegetation management work. Further, the Utility is required to implement a program to assess the age and expected useful life of certain electrical components in high fire-threat areas, incorporate this information into its risk-based asset management programs, and provide monthly progress reports to the Monitor. The Utility must also hire additional inspectors to oversee inspections of its transmission assets and implement a 90-day replacement requirement for cold end hardware in high fire-threat areas with an observed material loss approaching 50 percent.

On October 12, 2020, the court entered an order requesting that the Utility explain its role in the ignition of the 2020 Zogg fire. Regarding the Utility’s equipment removed by Cal Fire as part of Cal Fire’s investigation into the 2020 Zogg fire, the court ordered the Utility to describe, among other things, the location of the equipment when it was in use; whether the equipment was transmission line equipment, distribution line equipment, or substation equipment; and the extent of trimmed and untrimmed vegetation in the area near where Cal Fire took possession of the equipment.

On October 21, 2020, the court entered an additional order related to the 2020 Zogg fire, requesting that the Utility: (1) supply all documents, emails, text messages, reports, voicemails and any other materials related to “the decision to leave energized the line or circuit in question that possibly led to the Zogg Fire”; (2) identify the officer or other employee who made the decision to leave such line energized; (3) identify all others with any role in the decision or recommendation to leave such line energized; (4) describe “the sequence of all events that possibly relate to PG&E’s involvement in the ignition of the Zogg Fire” in chronological order; and (5) provide photographs or videos of the relevant scene. The Utility filed its response to both orders on October 26, 2020, including a detailed, chronologically ordered sequence of events potentially related to the 2020 Zogg fire.

On October 16, 2020, the federal Monitor overseeing the Utility’s probation filed a letter with the court, responding to the court’s “request for an update on the Monitor team’s field inspections of [the Utility’s] vegetation management and infrastructure inspection operations ~~liquidity~~since last year.” On October 20, 2020, the court entered an order noting that “[t]he Monitor has found more exceptions per mile this year than from September to December of last year” and ~~cash flows.~~that “as of August 31, 2020, [the Utility] failed to conduct any enhanced, ignition-based climbing inspections of the 967 applicable transmission structures selected for 2020 inspections in high-fire threat districts.” The court requested that the Utility “explain these shortcomings and any other points in the Monitor’s letter it wishes to address” by November 3, 2020.

On October 26, 2020, the court entered an additional order related to the 2020 Zogg fire, requesting that the Utility “state the extent to which the line in question had been cleared of vegetation within the last five years and the extent to which its records or its contractor records showed there was any vegetation that needed to be cut, but was not yet cut in the general area where equipment was seized by authorities.” The Utility included information responsive to the October 26, 2020 order in its response submitted that day and plans to provide a supplemental response with additional information responsive to the October 26, 2020 order at a future date.

For more information on the Utility’s probation, see the 2019 Form 10-K.

The Utility expects to ~~continue receiving~~receive additional orders from the court in the future.

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. Discussed below are significant regulatory developments that have occurred since filing the 2019 Form 10-K.

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 also remains unchanged. The cost of capital adjustment mechanism can trigger changes in the Utility’s authorized ROE and cost of debt, if the 12-month average Moody’s Baa bond rate for the period ending September 30, 2020 were to be 100 basis points higher or lower than 4.5 percent (the benchmark). The adjustment to i) ROE would be one-half the basis point change in the bond rate from the benchmark, and ii) authorized ~~bond costs~~cost of debt would be updated. 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 ~~April 20,~~May 28, 2020, the CPUC ~~also~~ issued a ~~proposed~~ decision in the OII to ~~consider~~Consider PG&E Corporation’s and the Utility’s Plan of Reorganization that ~~if approved, would direct~~directed the Utility to submit an Advice Letter to update its authorized cost of ~~debt.~~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.

For additional information, see the 2019 Form 10-K.

As previously disclosed, ~~as a result of the Tax Act,~~ on ~~October 17,~~September 13, 2019 the ~~CPUC approved the Utility’s~~Utility submitted an advice letter ~~including~~containing a revised computation of its revenue requirement due to the effects of the Tax Act, ~~on the revenue requirements, resulting in~~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 ~~these~~the gas revenue requirement ~~reductions~~increases into rates through its Annual Gas True-up advice letter beginning on January 1, 2020 and ~~later in 2020~~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 revenue requirement reduction of $175 million related to electric generation is amortized over 12 months and the 2018 revenue requirement reduction of $215 million related to electric distribution is amortized over 10 months. The Utility will incorporate the remaining 2019 revenue requirement reduction of $216 million related to electric distribution with other anticipated changes, such as the change in revenue requirement resulting from the 2020 GRC phase one decision. 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.

For additional information, see the 2019 Form 10-K.

~~As previously disclosed, on December 20, 2019,~~On October 23, 2020, the assigned ALJs issued a PD in the Utility’s 2020 GRC proceeding. In this proceeding, the CPUC will determine the annual amount of base revenues (or “revenue requirements”) that the Utility will be authorized to collect from customers for electric distribution, natural gas distribution, and electric generation operations from 2020 through 2022. In the 2020 GRC proceedings, the CPUC will also provide the Utility an opportunity to earn its authorized rate of return.

The PD proposes to adopt most of the provisions in the settlement agreement that the Utility, together with the Public Advocates Office of the California Public Utilities Commission, ~~(formerly known as Office of Ratepayer Advocates or ORA),~~ TURN, CUE, SED and certain other settling parties jointly submitted to the ~~CPUC’s Office~~CPUC on December 20, 2019 (the “settlement agreement”). The PD also proposes several modifications, including reduction of the Community Wildfire Safety ~~Advocate, the National Diversity Coalition, the Center~~Program (the “CWSP”) capital forecasts for ~~Accessible Technology, the Small Business Utility Advocates,~~2021 and ~~California City County Street Light Association filed a motion with the CPUC seeking approval~~2022. The PD includes less favorable procedural requirements for recovery of ~~a settlement agreement that resolves all~~undercollections tracked by certain regulatory accounts and for closure of ~~the issues raised by these parties in the Utility’s 2020 GRC.~~up to 10 customer service branch offices.

The PD proposes that the Utility’s 2019 authorized revenue requirement of $8.5 billion be increased by $585 million, effective January 1, 2020, to $9.102 billion, as requested in the settlement agreement. The PD revises the revenue requirement for 2021 and 2022 by reducing the Utility’s capital expenditure forecast for wildfire mitigation stated in the settlement agreement for 2021 and 2022. The PD provides for an additional increase of $339 million in 2021 to the authorized 2020 revenue requirement, or a 3.7% increase, and an additional increase of $344 million in 2022, or a 3.6% increase, as shown in the table below.

The PD proposes to adopt the revenue requirements for lines of business and cost categories proposed for 2020 in the settlement agreement. The following table shows the revenue requirements proposed in both the settlement agreement and the PD by line of business and cost category, as well as the differences between the 2019 authorized revenue requirements and the amounts in the settlement agreement adopted in the PD.

While the PD would adopt most of the settlement agreement, it proposes changes to the cost recovery process proposed in the settlement agreement for liability insurance, vegetation management and ~~based on other facts and circumstances known to PG&E Corporation and~~wildfire mitigation that are less favorable, by requiring that the Utility asfile applications for recovery of costs above 130% of the ~~date~~authorized amounts instead of ~~this filing, PG&E Corporation~~addressing such costs in an advice letter. In addition, the PD proposes reductions to wildfire mitigation capital in the CWSP to $603 million for each of 2021 and 2022, as compared to $931 million in 2021 and $1.15 billion in 2022 proposed in the ~~Utility expect to remain on track to satisfy the rate base conditions included in their exit financing documents.~~settlement agreement.

The PD proposes the 2019 weighted-average rate base of $27.7 billion to be increased by $1.7 billion, effective January 1, 2020, to $29.5 billion, or a 6.2% increase. The PD revises weighted average rate base amounts for 2021 and 2022, providing for a rate base of $30.9 billion in 2021, a 5.1% increase, and $32.7 billion in 2022, or a $5.5% increase, as shown in the table below. The rate base amounts for 2020 through 2022 proposed in the PD include $1.95 billion in total of forecast capital spend that will not earn an equity return, pursuant to AB 1054, or $147 million for August to December 2019, and $601 million for each of 2020, 2021 and 2022. (The rate base amounts proposed in the settlement agreement included $147 million for August to December 2019, $601 million for 2020, $930 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 PD provides average annual capital investments of approximately $4.3 billion in electric distribution, natural gas distribution and electric generation infrastructure, as compared to $4.5 billion in the settlement agreement. (While the settlement agreement proposed overall revenue requirement increases for 2021 and 2022, it did not specify capital expenditures for those years.)

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 ~~is unable~~did not seek recovery of compensation of PG&E Corporation’s and the Utility’s officers.

The CPUC could vote on the PD no earlier than at its meeting scheduled for December 3, 2020. Settling parties’ notice to ~~predict~~accept the ~~timing and outcome of this proceeding.~~PD or motion protesting the changes to the settlement are due 15 days after the date the Commission formally issues its final decision.

On June 30, 2020, the Utility filed the 2020 Risk Assessment Mitigation Phase Report.

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 decision, 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.

For additional information, see the 2019 Form 10-K.

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 result in any additional disallowances. The 2015 GT&S decision authorized the Utility ~~would be required~~ to ~~take~~seek recovery of costs not otherwise disallowed through a ~~charge~~separate application upon completion of the audit. On July 31, 2020, the Utility filed an application seeking recovery of $512 million (on a recorded basis). On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. The scoping memo requires the Utility to provide supplemental testimony on January 20, 2021 addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the ~~future if the CPUC’s audit~~fourth quarter of ~~2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process. The Utility cannot predict the timing and outcome of the audit.~~2021.

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.~~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.

For additional information, see the 2019 Form 10-K.

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 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.

For additional information, see the 2019 Form 10-K.

As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a ~~50 basis~~50-basis point ROE incentive adder for its continued participation in the CAISO. If 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 FERC for further proceedings consistent with the Court of Appeals’ opinion.

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

Also as previously disclosed, on September 16, 2019, FERC extended the amount of time it has to consider the request for rehearing by issuing a tolling order for the limited purpose of further consideration of the matters raised in the request. On March 17, 2020, FERC issued its order denying the ~~request~~requests for ~~rehearing~~rehearing. On May 11, 2020, the CPUC and ~~re-affirming~~a number of other parties filed a petition for review of FERC’s orders in the ~~Utility’s eligibility to receive~~Ninth Circuit Court of Appeals. Briefing on the ~~50 basis point ROE incentive adder.~~appeal will be completed in December 2020. The Utility is unable to predict the timing and outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case at 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 return on equity 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 10.90%, and an estimated composite depreciation rate of 2.96% compared to the Utility’s request of 3.25%. ~~The ALJ also rejected the Utility’s method of allocating common plant between CPUC and FERC jurisdiction.~~ 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.

~~Once~~On October 15, 2020, 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 FERC’s revised ROE methodology adopted in FERC ~~issues its decision,~~Opinion No. 569-A, issued on May 21, 2020, which refined the ~~Utility expects one or more parties~~methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to ~~seek rehearing~~earn on electric transmission investments. Initial briefs are due 60 days from the date of ~~that~~this decision and ~~then appeal it~~responses are due 30 days later. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the ~~courts.~~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, 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.

In addition to the additional return on equity briefing, the order is subject to requests for rehearing and potential appellate review of any rehearing order. The Utility is unable to predict the timing and outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case at 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 ana 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 ~~FERC~~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. Additionally, on July 18, 2019, the FERC issued an order on remand reaffirming its grant of the Utility’s request for the 50 basis point incentive adder for continued CAISO participation. On September 30, 2019, the FERC issued an order on rehearing that denied a pending request for rehearing of the FERC’s decision granting the 50 basis point ROE adder in the TO19 proceeding.

For additional information, see the 2019 Form 10-K.

As previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case at 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~~Effective Date for rate changes. FERC also ordered that the hearings will 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 will be 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 will be either collected from or refunded to customers.

The parties conducted several settlement conferences throughout 2019. On March 31, 2020, the Utility filed a partial settlement with 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.

On May 9, 2019, the Utility filed a request with the FERC to modify the formula rate determination of the Utility’s capital structure to address certain non-cash charges related to wildfire liability. The filing was accepted by FERC, subject to hearing and refund, on July 8, 2019 and was consolidated with the TO20 rate case. In addition, on June 30, 2020, the Utility filed another request with the FERC to modify the formula rate determination of the Utility’s capital structure to address certain financing issuances related to the Utility’s emergence from Chapter 11 and requirements of AB 1054. The filing was accepted by FERC, subject to hearing and refund, on August 28, 2020 and was consolidated with the TO20 rate case (together, the “Formula Rate Proceedings”).

On March 31, 2020, the Utility filed a partial settlement with 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 FERC authorization before recovering claims related to 2017 Northern California wildfires and 2018 ~~fires.~~Camp fire. The partial settlement was approved by FERC on August 17, 2020.

On October 15, 2020, the Utility filed a settlement with 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, if approved by FERC, 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 ~~unable~~pending at FERC. The settlement also provides that the Utility will make supplemental filings in two FERC dockets addressing the calculation of the Utility’s AFUDC to ~~predict~~reflect the ~~timing and outcome~~terms of ~~this proceeding.~~the settlement. The two AFUDC dockets have not been consolidated with the Formula Rate Proceedings but include capital structure issues addressed by the settlement.

For additional information, see the 2019 Form 10-K.

The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating licenses. 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 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.

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

~~104~~

On ~~June 20, 2016,~~February 7, 2020, the Utility ~~entered into~~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 ~~joint proposal with certain parties, including~~request on March 23, 2020, to reduce the ~~Alliance for Nuclear Responsibility,~~interim rate relief by $8.4 million to ~~retire Diablo Canyon’s two nuclear power reactor units at~~ the ~~expiration of their current operating licenses in 2024 and 2025. On January 11, 2018,~~proposed revenue requirement. This reduction, which reduces the ~~CPUC approved~~requested rate relief to $891 million, relates to the ~~planned retirement~~capital cost reduction required by 2024 and 2025, but required legislative authorization for certain key aspects of the joint proposal. On November 29, 2018, in response to SB 1090, the CPUC issued a further decision addressing the key remaining goals of the Diablo Canyon joint proposal agreement.Assembly Bill 1054.

On October 1, 2019, the Alliance for Nuclear Responsibility filed a PFM of the CPUC’s January 11, 2018 decision approving the planned retirement of Diablo Canyon. The PFM argues that above-market costs attributable to Diablo Canyon under the Power Charge Indifference Adjustment methodology, when combined with decreasing bundled load by the Utility, create material changed circumstances that undermine the reasonableness of incurring costs to operate Diablo Canyon until its retirement. On October 31, 2019, the Utility filed a joint response with Friends of the Earth, Natural Resources Defense Council, CUE, and IBEW Local 1245, which argued that modification of the CPUC’s initial decision is not warranted and is not in the public interest. On February 7, 2020, the ALJ issued a PD denying the Alliance for Nuclear Responsibility’s PFM. On March 18,22, 2020, the CPUC voted out its final decision that approved interim relief in the ~~PD and closed the proceeding.~~amount of $447 million. The Utility will recover these costs over a 17-month period beginning in January 2021.

For additional information, see the 2019 Form 10-K.

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities (the “WMCE application”). The recorded expenditures exclude amounts disallowed as a result of the CPUC’s decision in the Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp fire and consist of $1.18 billion in expense and $801 million in capital expenditures, which result 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 recorded these costs to the FHPMA of $293 million, the FRMMA of $112 million, the WMPMA of $608 million, and the CEMA of $251 million. The 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, the Utility proposes to recover the remaining $868 million revenue requirement 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.

The Utility has proposed a schedule that would call for a final decision by the CPUC in September 2021.

The Utility is unable to predict the timing and 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 Accounts” and “Catastrophic Event Memorandum Accounts and Applications” below.

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 for the cost of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019 that is incremental to the insurance costs already authorized in the 2017 GRC or sought to be authorized in rates in 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. The Utility has proposed a schedule for the proceeding that requests a final decision by the end of 2020 and costs to be recovered in 2021.

On April 2, 2020, the CPUC held a prehearing conference in this matter. The CPUC has yet to issue a scoping memo that would establish the scope and schedule for the proceeding.

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 the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in the CEMA. The Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA application requesting cost recovery of $159.3 million in connection with ~~thirteen~~13 catastrophic events that included ~~twelve~~12 wildfires and one storm for declared emergencies from mid-2017 through 2018. The 2019 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire. ~~A prehearing conference was held on November 4, 2019~~

On June 30, 2020, the Utility reported that it reached a settlement in principle with TURN and the PAO, and asked the ALJ to suspend the scheduled evidentiary hearings and give the parties time to finalize a ~~scoping memo was issued on December 6, 2019.~~ settlement.

On ~~March 10,~~August 31, 2020 the Utility filed a ~~Motion for Interim Rate Relief, requesting $135.4 million~~joint motion on behalf of ~~interim rates to be recovered starting August 2020. On April 7, 2020,~~ the ~~ALJ granted~~settling parties seeking approval and adoption of the ~~Utility’s request to withdraw the motion without prejudice. The Utility may refile it should the 2019 CEMA schedule be delayed.~~settlement agreement. A final decision is expected by the end of 2020.

PG&E Corporation and the Utility are unable to predict the outcome of this ~~overall~~ proceeding.

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

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs (63% of the total costs incurred in 2016 and 2017), compared to $588 million requested by the Utility. 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 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, requiring the Utility to file by June 30, 2020 a revised application that would include actual 2019 ~~vegetation management~~tree mortality costs and an independent auditor to be hired for audit of all vegetation management costs and related interest calculations.

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.

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

The Utility requested recovery of costs recorded in the 2018 CEMA in its Wildfire Mitigation and Catastrophic Events Interim Rates Application described above. (See “Wildfire Mitigation and Catastrophic Events Interim Rates Application.”)

For additional information, see the 2019 Form 10-K.

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 of the CPUC, the CPUC’s Office of the Safety Advocate, 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 11 of the Notes to the Condensed Consolidated Financial Statements.

Other than the amounts subject to the settlement agreement, as modified by the Decision Different ~~issued~~approved on ~~April 20,~~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 and authorization in a separate proceeding or through a GRC.~~review.

~~For~~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 ~~recorded to~~reflected in this memorandum account as of ~~March 31,~~September 30, 2020 was $259 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

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 by SB 901 and AB 1054 to capture mitigation costs of activities not included in a CPUC approved Wildfire Mitigation Plan. The Utility has proposed that the FRMMA continue after the approval of its 2019 Wildfire Mitigation Plan to record costs of wildfire mitigation activities that were beyond the initial identified scope of ~~work.~~work or are not included in the subsequent wildfire mitigation plans.

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, 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, 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 11 of the Notes to the Condensed Consolidated Financial Statements.

~~Other than~~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 ~~issued~~approved on ~~April 20,~~May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp ~~fire, the Utility intends to seek recovery of the FRMMA balance in a future application, which rate recovery requires CPUC reasonableness review~~fire. (See “Wildfire Mitigation and ~~authorization in a separate proceeding or through a GRC.~~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.

~~For the~~The amount ~~recorded to~~reflected in this memorandum account as of ~~March 31,~~September 30, 2020 was $99 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

As previously disclosed, on June 5, 2019, the Utility submitted an advice letter to establish the WMPMA (also called the Wildfire Plan Memorandum Account) effective May 30, 2019. The purpose of the WMPMA is to track costs incurred to implement the Utility’s Wildfire Mitigation ~~Plan,~~Plans, as required by Public Utilities Code Sections 8386 et ~~seq,~~seq., as modified by SB 901 and subsequent bills including AB 1054, AB 111, SB 70, SB 167, SB 247, and SB 560. The WMPMA is required to be established upon approval of a utility’s wildfire mitigation plan to track costs incurred to implement the plan. The CPUC approved the memorandum account on August 5, 2019, so the Utility ~~will record any~~has recorded costs incurred in implementing ~~an approved~~the Wildfire Mitigation Plan, which was approved May 30, 2019, as of the ~~effective date,~~WMPMA Effective Date, June 5, 2019.

~~For the~~The amount ~~recorded to~~reflected in this memorandum account as of ~~March 31,~~September 30, 2020 was $1.08 billion, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

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

The Resolution also authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the Resolution.

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 accounts receivable financing costs 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 September 30, 2020 was $53 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On September 30, 2020, the Utility filed an application with the CPUC to authorize it to sell its San Francisco General Office headquarters complex (the “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 relocate and consolidate this site and certain East Bay office locations into a single Bay Area corporate headquarters located at 300 Lakeside Drive in Oakland (the “Lakeside Building”), and for appropriate ratemaking treatment of those transactions.

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

In this application, the Utility requests that the CPUC: (i) authorize the Utility to sell the SFGO; (ii) approve the Utility’s proposal to distribute all of the gain on sale of the SFGO to customers on an annual basis over a period of five years, beginning in 2022; (iii) determine that the Transactions are reasonable, and authorize the Utility to recover (a) the costs of exercising the option to purchase the Lakeside Building and include the costs in rate base; (b) the costs of leasing necessary space in both the SFGO and in the Lakeside Building during the transition period (with the SFGO leased space decreasing as the Lakeside Building space increases); and (c) other transition and/or transaction-related costs, in accordance with the ratemaking treatment requested; and (iv) 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.

PG&E Corporation and the Utility are unable to predict the timing and outcome of this proceeding.

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. As a result of the proposed transaction, the Utility would retire $6.0 billion of ~~temporary~~ Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date. Specifically, the application requests 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 asks that the CPUC proceed with reviewing the Utility’s requests while the Utility is still in Chapter 11 because the CPUC would issue a decision applying the Stress Test only after the Utility emerges from Chapter 11 and because, given the developments in the Chapter 11 proceeding and related Chapter 11 Proceedings OII that have occurred since the CHT decision, the CPUC and other parties now have access to information to assess the Utility’s “financial status” pursuant to the Stress Test. The application also contemplates a customer credit designed to 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 anticipates that this will be sufficient to ensure that the customer credits equal the bond charges over the life of the bonds. 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 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 ~~foregoing description of anticipated~~Assigned Commissioner issued the scoping memorandum on July 28, 2020 and directed the Utility to file updated testimony, if any, based on its post-emergence securitization transaction includes “forward-looking statements” within the meaning of Section 27A of the Securities Act, including statements about the expected sources and uses of funding, expected financing transactions (including the potential securitization) and projected balances of assets and liabilities (including cashfinancial status by August 7, 2020. The Utility served its updated testimony on ~~hand, accrued interest, trade payables and~~August 7, 2020, in which it discussed , among other ~~amounts). This description reflects~~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, as well as certain expected tax impacts.

Intervenor testimony was served on October 14, 2020, and the Utility’s ~~expectations as of the date of this filing~~rebuttal testimony is due on November 11, 2020. An evidentiary hearing is scheduled to commence on December 7, 2020. Opening briefs are due on January 7, 2021, and ~~remains subject to change. (See “Forward-Looking Statements” above).~~reply briefs are due on January 22, 2021.

As previously disclosed, on October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility wildfire mitigation plans. This OIR provided guidance on the form and content of the initial wildfire mitigation plans, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of wildfire mitigation plans 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 wildfire mitigation plans. 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 wildfire mitigation plans, which SB 901 requires to be addressed in separate rate recovery applications.

On February 6, 2019, the Utility filed its wildfire mitigation plan (the “2019 ~~Wildfire Mitigation Plan”~~WMP”) with the CPUC, and amended it subsequently on February 12 and February ~~14, and~~14. On May 30, 2019, the CPUC approved the 2019 WMP. (The Utility also filed an amendment to the plan on April 25, ~~2019.~~

For additional information, see the 2019 Form 10-K.

As previously disclosed, on February 7, 2020, the Utility publicly posted its 2020 Wildfire Mitigation Plan (the “2020 WMP”) and utility survey. The Utility’s 2020 ~~Wildfire Mitigation Plan~~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.

On March 18, 2020, the CPUC issued a decision in this proceeding, clarifying that the CPUC’s newly created Wildfire Safety Division will review 2020 wildfire mitigation plans, 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.

~~Also,~~On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved PG&E’s 2020-2022 WMP. The resolutions indicate that while the Utility’s 2020-2022 WMP met the minimum requirements for its submission, the deficiencies found, classified as ~~previously disclosed, PG&E Corporation~~Conditions A, B, or C, will require significant oversight to ensure they appropriately prioritize and remedy the deficiencies. The Utility received 41 Conditions in total with the first set classified as Conditions A, which were completed on July 27, 2020. The second set, Conditions B were completed on September 9, 2020 and the ~~Utility expect~~third, Conditions C are due as part of the ~~CPUC to issue a decision on its 2020-2022~~2021 WMP ~~by June 2020.~~ update in February 2021.

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 ~~Wildfire Mitigation Plan,~~WMP, and the 2020-2022 ~~Wildfire Mitigation Plan~~WMP recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.

For additional information, see the 2019 Form 10-K.

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 ~~is seeking~~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. ~~A decision giving direction for mitigation measures ready for implementation by September 1, 2020 is expected to be voted on by the CPUC as early as June 11, 2020.~~ At the CPUC’s direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility’s proposal ~~contains~~contained three components for which it is ~~seeking~~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 iswas 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’s supplemental testimony also attached contracts the Utility had executed with mobile generation vendors for over 300 megawatts of capacity for use~~ in 2020. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying on procedural grounds the Utility’s motion to supplement its proposal. ~~On April 29,~~

The CPUC adopted a decision in the first track of the proceeding on June 11, 2020, ~~the CPUC issued a proposed decision that would conditionally approve~~which approved with conditions each of the Utility’s ~~proposal~~three proposed components and ~~would allow~~requires the Utility to track costs in ~~the FRMMA.~~a new memorandum account. The ~~proposed~~ decision ~~would require~~requires the Utility to seek recovery of the recorded costs for the temporary, mobile generation and associated substation facility equipment in a future ~~application, which would require CPUC~~track of the proceeding. The decision requires the Utility to seek recovery of the costs of the community microgrid enablement program through reasonableness review ~~and authorization~~ in a future separate application or a general rate case.

The CPUC initiated the second track of the proceeding ~~or through~~on July 3, 2020, which will focus on further implementation of SB 1339, as well as activity to shape the transition from diesel mobile generation to alternative, clean backup power generation. As part of the second track, the CPUC issued a ~~GRC.~~staff proposal on September 4, 2020, describing an interim approach for providing temporary power at substations during the 2021 wildfire season, and a process for completing the transition to clean technologies and fuels in future years. The Utility expects the CPUC to issue a decision on temporary generation policy for the 2021 wildfire season and beyond by the end of 2020.

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.

The Utility has approximately 450 megawatts of temporary generation reserved for use in 2020.

For additional information, see the 2019 Form 10-K.

As previously disclosed, on July 8, 2019, the CPUC issued a decision in the CHT proceeding, which 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% of the CHT or 5% of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

~~Failure~~Pursuant to ~~obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s~~SB 901 and the ~~Utility’s financial condition, results~~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 securitize $7.5 billion of ~~operations, liquidity~~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 the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and ~~cash flows.~~

For additional information, see “Application for Post-Emergence Securitization Transaction” above and the 2019 Form 10-K.

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 ~~January 22,~~May 28, 2020, the ~~Utility entered into~~CPUC approved a RSA with members of the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility and, consistent with that agreement, on January 23, 2020, the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility filed a motion to withdraw from the proceeding. On January 30, 2020, the ALJ issued a ruling allowing the Ad Hoc Committee of Senior Unsecured Noteholders to withdraw as a party.

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 that moves certain work to local regions for both scheduling and execution. 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 is unable to predict the timing and outcome of this application.

◦~~a requirement of consultation with~~In the Chapter 11 Proceedings OII final decision, the CPUC ~~regarding Board member candidates for at least seven years following emergence from Chapter 11; and~~

For ~~additional~~more information about this OII, see PG&E Corporation’s and the Utility’s joint 2019 Form 10-K.

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of ~~a non-bypassable charge~~an NBC to support the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision finding that the imposition of the ~~non-bypassable charge~~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 investor-owned utilities 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 will be imposed to collect revenue from electric customers of the Utilities will be 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 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, submitted on September 25, 2020.

For additional information, see the 2019 Form 10-K.

SB 350 (the Clean Energy and Pollution Reduction Act), requires the CPUC, in consultation with the CARB and the California Energy Resources Conservation and Development Commission, to direct electrical corporations to file applications for programs and investments to accelerate widespread transportation electrification. In September 2016, the CPUC directed the Utility and the other large IOUs to file transportation electrification applications that include both short-term projects (of up to $20 million in total) and two-to-five year programs with a requested revenue requirement determined by the Utility.

As previously disclosed, on May 31, 2018, 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 December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters. This new proceeding will include issues related to utility rate designs supporting transportation electrification and hydrogen fueling stations, a framework for IOUs’ transportation electrification investments, and vehicle-grid integration. A prehearing conference for this rulemaking was held on March 1, 2019. On May 2, 2019, the assigned commissioner issued a scoping memo and ruling for the proceeding, which sets forth the category, issues to be addressed, and schedule of the proceeding. On February 3, 2020 the CPUC issued a draft Transportation Electrification Framework for review and comment. The CPUC has held workshops in 2020. Approval of the framework is expected by early 2021.

For additional information, see the 2019 Form 10-K.

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 greenhouse gas 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). ~~Initial workshops are scheduled~~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 September 14, 2020, the assigned ALJ issued a Ruling modifying the procedural schedule to allow additional time for ~~July~~CPUC staff to issue a workshop report including recommendations. In accordance with the revised procedural schedule for Phase I, the CPUC staff is expected to issue its Report on October 2, 2020. Parties may then submit opening and reply comments in November 2020 on the Report.

For additional information, see the 2019 Form 10-K.

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 investor-owned utilities 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~~the CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed ~~utilities~~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 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 ~~remaining topics~~CPUC instructed IOUs to establish “climate change teams,” 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 ~~phase~~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 seek to obtain and 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 IOUs must detail resulting climate adaptation measures in a new chapter in 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 CEP proposals must be filed one ofyear prior to their CVA, with the Utility’s first CEP due in June 2023, as PG&E’s first CVA under this ~~proceeding are still under consideration and~~decision will be ~~subject~~due in June 2024. A new memorandum account, the Climate Adaptation Vulnerability Assessment Memorandum Account, was authorized, to ~~a separate decision. Those issues include: guidance on how climate adaptation should be incorporated into the investor-owned utilities’ investment plans, program design,~~cover CVA costs and ~~operations and how climate change might affect vulnerable and disadvantaged communities. The CPUC decision on such issues is anticipated no earlier than mid-2020.~~incremental costs of outreach.

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. Parties submitted opening and reply comments on the guidelines on February 19, 2020 and February 26, 2020, respectively.

As discussed above, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. The requested requirements included providing back-up generation to essential services and allowing local governments to veto PSPS events for their areas. The Utility and other entities (including the other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. On August 24, 2020, the ALJ issued a decision holding the April 13, 2020 joint motion in abeyance, finding that the May 28, 2020 decision dealt with many of the issues raised. If the motion were reinstated in the future, a CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events.

On May 28, 2020 the CPUC adopted PSPS Phase 2 Guidelines, which requires 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. The CPUC’s ~~April 27,~~May 28, 2020 ~~proposed~~ decision did not act on ~~this~~the joint motion. ~~PG&E Corporation~~

On June 15, 2020, 14 parties (including telecommunications providers, CCAs, and 10 cities and counties) filed a joint motion requesting that the ~~Utility are unable~~CPUC perform a reasonableness review of past IOU PSPS events to ~~predict~~determine whether each was reasonable. In its August 24, 2020 decision, the ~~timing and~~CPUC denied the ~~outcome~~June 15, 2020 motion, finding that the CPUC already performed reasonableness reviews of ~~this request.~~IOU PSPS events.

For additional information, see the 2019 Form 10-K.

On November 12, 2019, the assigned commissioner and ALJ in the OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions issued an order to show cause directing the Utility to show cause 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 ~~23-November~~26-November 1, 2019.

The Utility filed its testimony with the CPUC on February 5, 2020.Parties filed testimony on February 28, 2020; concurrent rebuttal was filed on April 7, ~~2020; and hearings have been~~2020. On April 16, 2020, proceedings in the order to show cause phase of this proceeding were suspended indefinitely pending the COVID-19-related restrictions. On July 7, 2020, in response to an email ruling from the ALJ, parties in the order to show cause submitted a joint response that discussed, among other things, the need for evidentiary hearings in the proceeding and a proposed schedule for the remainder of the proceedings. On July 9, 2020 and August 27, 2020, the ALJ held status conferences at which parties discussed those issues. On September 21, 2020, the assigned commissioner and the ALJ issued an order that required the Utility to provide responses to certain factual questions regarding the issues in the proceeding, concluded that with the provision of responsive answers to those questions evidentiary hearings would not be needed in the proceeding, and established a schedule for the remainder of the proceeding. The schedule provides for concurrent opening briefs to be filed on October 30, 2020; concurrent reply briefs on November 17, 2020; a presiding officer decision no later than 60 days following submission; and a final decision no sooner than 30 days after the presiding officer decision if no appeal or request for review is submitted.

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

For additional information, see the 2019 Form 10-K.

On November 13, 2019, the CPUC issued an OII to determine “whether California’s investor-owned utilities prioritized safety and complied with the ~~Commission’s~~CPUC’s regulations and requirements with respect to their Public Safety Power Shutoff (PSPS) events in late 2019.” The first phase of this proceeding will assess for each utility, among other things, (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 indicated that it described the manner and extent to which each electric investor-owned utility implemented the CPUC’s PSPS Guidelines during their late 2019 PSPS events. The Report stated that it was intended to be advisory in nature, subject to modification, and not intended to serve as an adjudicatory-staff investigatory pre-enforcement report. On June 19, 2020, parties to the OII submitted prehearing statements that provided, among other things, views on the appropriate next steps in the proceeding. On June 22, 2020, the ALJ held a prehearing conference that discussed appropriate next steps in the proceeding. On August 3, 2020, the ALJ issued a ruling finding that a hearing was not necessary and setting the schedule for the proceeding, and on September 18, 2020, the ALJ granted a motion to extend time for intervenor and reply comments. IOU comments were submitted September 2, 2020, intervenor comments were submitted October 16, 2020, and reply comments are due November 16, 2020. The proposed decision is anticipated 90 days after submission of reply briefs, and the CPUC decision is anticipated no sooner than 30 days after issuance of the proposed decision.

Also 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 ~~is unable~~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 should the CPUC should require of the Utility and other IOUs for any failure in late 2019 to ~~predict~~comply with the ~~timing or outcome of this proceeding.~~then-existing PSPS guidelines

For additional information, see the 2019 Form 10-K.

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, resource adequacy (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. A PD is expected in the ~~third~~fourth quarter of 2020.

For additional information, see the 2019 Form 10-K.

On June 17, 2020, the CPUC issued a decision on the Central Procurement of the RA Program. The decision adopted implementation details for the central procurement of multi-year local RA procurement, ordered the Utility and another IOU to serve as the central procurement entities 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 central procurement entity 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.

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.

On June 30, 2020, the California governor signed into law SB 350 (the Golden State Energy Act), a bill which authorizes the creation by the governor 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.

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. ~~SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.~~

For additional information, see the 2019 Form 10-K.

On July 12, 2019, the California ~~Governor~~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 calendar 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.

Each California large investor-owned electric utility that is not currently subject to Chapter 11 (Southern California Edison Company and San Diego Gas & Electric Company) has elected to participate in the Wildfire Fund to be established under AB 1054. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund (which participation is subject to the conditions set forth in AB 1054, including those conditions outlined below).

Each of California’s large investor owned utilities have elected to participate in the Wildfire Fund. On July 1, 2020, having satisfied the conditions for the Utility’s participation in the Wildfire Fund, the Utility deposited approximately $5 billion in the Wildfire Fund, which represents PG&E’s initial and first annual contributions.

For additional information, see the 2019 Form 10-K.

In addition to other requirements, SB 378 would impose on an electric utility company a civil penalty of at least $250,000 per 50,000 affected customers for every hour that a PSPS event is in place, would require the CPUC to establish a procedure for customers, local governments and others to recover costs accrued during a PSPS event from the electric utility company, which cost recovery would be borne by shareholders, and would prohibit an electric utility company from billing customers for any nonfixed costs during a PSPS event.

AB 1941 proposes to suspend RPS requirements, determine the savings to electric utility companies from the suspension and direct those savings towards system hardening to mitigate wildfire risks and PSPS impacts, and would prohibit salary increases or bonuses to executive officers during the suspension of RPS requirements.

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; the reporting and reduction of carbon dioxide and other greenhouse gas 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 Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.)

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and MD&A “Contractual Commitments” in Item 7 of the 2019 Form 10-K.

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 in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K (the Utility’s commodity purchase agreements).

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 risk mitigation purposes and not for speculative purposes. 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, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. 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. These activities are discussed in detail in the 2019 Form 10-K. There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the ~~three~~nine months ended ~~March 31,~~September 30, 2020.

The preparation of the Condensed 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 Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for ~~LSTC,~~ regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, and pension and other post-retirement benefit plans to be critical accounting policies. These policies are considered critical accounting policies 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 and their key characteristics are discussed in detail in the 2019 Form 10-K.

On the Effective 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. As of September 30, 2020, PG&E Corporation and the Utility have nine remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as 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 calendar 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.

In the second quarter of 2020, PG&E Corporation and the Utility recorded a current liability of $5.2 billion in “Wildfire fund liability” and $1.5 billion in Other noncurrent liabilities for the present value of unpaid contribution amounts, as well as $6.5 billion in assets for its commitment to make contributions, reduced by amortization, of which $6.0 billion were non-current, called “Wildfire fund asset” in the Condensed Consolidated Balance Sheets. The initial contribution and first annual contribution were paid in the third quarter of 2020. During the three and nine months ended September 30, 2020, the Utility recorded amortization and accretion expense of $120 million and $293 million, respectively. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in “Wildfire fund expense” in the Condensed Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US 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 starting with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment. 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 of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Using a 5 year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would decrease the amortization period to 6 years. Similarly, a ten percent change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility evaluate all assumptions quarterly, or 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 in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment 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. At September 30, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.

See the discussion above in Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. (See the section above entitled “Risk Management Activities” in MD&A and in Note 8 and Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of ~~March 31,~~September 30, 2020, 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 Securities Exchange Act of 1934, as amended, 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.

There were no changes in internal control over financial reporting that occurred during the quarter ended ~~March 31,~~September 30, 2020, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s legal proceedings and contingencies, see Notes 2, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, MD&A: “Enforcement and Litigation Matters.”

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count 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.

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

Upon the court’s request, on March 2, 2020, the Utility provided to the court its target number of contract tree trimmers for 2020, information regarding the Utility’s 2019 inspections of Tower 009/081 on the Cresta-Rio Oso 230 kV Transmission Line (the “Cresta-Rio Oso Line”), information regarding the relationship between priority codes set forth in the Utility’s Electric Transmission Preventive Maintenance Manual and the safety factors specified in General Order 95 promulgated by the CPUC, as well as the application of each to the C-hooks of interest on the Cresta-Rio Oso Line. In addition, on April 2, 2020, the Utility submitted a report to the court regarding the Utility’s March 19, 2020 collection of equipment from the Cresta-Rio Oso Line. On April 10, 2020, the TCC in the Utility’s Chapter 11 ~~bankruptcy case~~Cases and estimation proceedings filed a declaration from a TCC expert concerning Cresta-Rio Oso 230kV Transmission Line evidence collection and removal on March 19, 2020.