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 the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation 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~~were subject to an automatic stay. ~~Absent an~~Except as otherwise set forth in the Plan, the Confirmation Order (as defined below) or another order of the Bankruptcy Court, ~~providing otherwise,~~ substantially all pre-petition liabilities ~~will be~~were 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, 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 insurance subrogation claims (collectively, the “Consenting Subrogation Creditors”) (as amended, the “Subrogation RSA”). ~~On September 22, 2019,~~As of June 30, 2020, 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 pursuantincurred $52 million in professional fees related to the Plan in order to settle all insurance subrogation claims (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. 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) (the “Fire Victim Claims”)~~, upon the terms and conditions set forth in~~ that are signatories to the TCC RSA (each a “Consenting Fire Claimant Professional”), 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.

~~Plan of Reorganization~~

On March 20, 2020, PG&E Corporation and the ~~Debtors~~Utility filed a motion with the Bankruptcy Court (the “Case Resolution Contingency Process Motion”) for entry of an order approving a case resolution contingency process to address the circumstance in which the Plan is not confirmed or fails to become effective in accordance with certain required dates (the “Case Resolution Contingency Process”). ~~As further described in the motion, the~~The Case Resolution Contingency Process contemplates a process for the sale of PG&E Corporation or the Utility in the event that the Plan is not confirmed or fails to become effective in accordance with certain required dates. In addition, the motionMotion sets forth certain other commitments by PG&E Corporation and the ~~Debtors~~Utility in connection with the confirmation process and implementation of the Plan, including among other things, limitations on the ability of PG&E Corporation to pay dividends; commitments by the Utility with respect to cost recovery of amounts paid in respect of “Fire Claims” under the Plan; the terms of a purchase option in favor of the state of California (which would be exercisable only in limited circumstances); and commitments with respect to the Utility’s utilization of the cash benefits associated with wildfire-related net operating losses. Also on March 20, 2020, the California Governor filed a responsive pleading in the Bankruptcy Court stating that, assuming the Bankruptcy Court grants the Motion and the California Public Utilities Commission (“CPUC”) approves the Plan with the governance, financial and operational provisions submitted to the CPUC by the Utility or otherwise agreed by the Utility, with any modifications the CPUC believes appropriate or necessary, the Plan “will, in the Governor’s judgment, be compliant with AB 1054.” The Governor’s pleading also states that “a rate neutral securitization pursuant to Senate Bill 901...would, in [the Governor’s] judgment, be in the public interest...” Following a hearing held on April 7, 2020, the Bankruptcy Court indicated that it would approve the Debtors’ motion and the Case Resolution Contingency Process, subject to certain reservations of rights, and directed the Debtors to submit an order to that effect. The Bankruptcy Court entered the order approving the ~~motion~~Case Resolution Contingency Process Motion on April 9, 2020.

~~Disclosure Statement~~On May 28, 2020, the CPUC approved, with conditions and modifications, the Plan pursuant to the requirements of Assembly Bill 1054. Pursuant to the decision, changes to the Utility’s governance structure and enhancements to the CPUC’s oversight have been put in place to facilitate the Utility’s ability to provide safe, reliable and affordable utility service. The CPUC’s final decision was issued on June 1, 2020.

~~On February 7, 2020, pursuant to section 1125~~The Plan as confirmed by the Confirmation Order provides for certain transactions and the satisfaction and treatment of ~~the Bankruptcy Code,~~claims against and interests in PG&E Corporation and the Utility, ~~filed a proposed disclosure statement (as updated,~~each in accordance with the ~~“Proposed Disclosure Statement”), with all schedules and exhibits thereto, for~~terms of the ~~Plan. On February 18, 2020,~~ Plan, including the following transactions:

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

The Confirmation Order contains a Channeling Injunction that is also in the Plan that provides, among other things, that the sole source of recovery for holders of Subrogation Wildfire Claims will be from the Subrogation Wildfire Trust and the sole source of recovery for holders of Fire Victim Claims will be from the Fire Victim Trust. The holders of such Claims will have no recourse to or Claims whatsoever against PG&E Corporation and the Utility or their assets and properties.

The Plan as confirmed by the Confirmation Order provides for certain financing transactions as follows:

As described below, the foregoing financing transactions occurred on or around the Effective Date.

On January 22, 2020, PG&E Corporation and the Utility entered into the Noteholder RSA with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” ~~below~~therein and the Shareholder Proponents. The Noteholder RSA provides for, among other things, (i) the refinancing of the Utility’s senior unsecured debt in satisfaction of all claims arising out of the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt, ~~each as defined below,~~ and (ii) the reinstatement of the Utility Reinstated Senior Notes ~~as defined below~~ (together with the Utility Short-Term Senior Notes and Utility Long-Term Senior Notes, the “Utility Senior Note Claims”), in each case pursuant to the Plan and upon the terms and conditions set forth in the Noteholder RSA. Under the Noteholder RSA, PG&E Corporation and the Utility ~~have~~ also agreed to reimburse the holders of Utility Long-Term Senior Notes for debt placement fees and the members of the Ad Hoc Noteholder Committee for professional fees of up to ~~$99~~$106 million upon the terms and conditions set forth in the Noteholder RSA. ~~The following holders of~~On July 1, 2020, the Utility ~~Senior Notes Claims are party to~~recorded $102 million in fees as additional debt discount on the Noteholder RSA as “Consenting Noteholders” as of the date hereof: Apollo Global Management LLC, Elliott Management Corporation, Oaktree Capital Management L.P., Farallon Capital Management LLC, Capital Group, Värde Partners Inc., Davidson Kempner Capital Management LP, Canyon Capital Advisors LLC, Third Point LLC, Pacific Investment Management Company LLC, Citadel Advisors LLC and Sculptor Capital Investments, LLC. Any holder of Utility Senior Note Claims or Utility Funded Debt can become a party to the Noteholder RSA by executing the joinder attached to the Noteholder RSA.Utility’s refinanced debt.

The Noteholder RSA provides for the following treatment of Utility Senior Note Claims and Utility Funded Debt which treatment ~~has been~~was incorporated into the Plan:

As described below in Note 12, on July 27, 2020, Elliott Management Corporation, a Consenting Noteholder, filed a motion with the Bankruptcy Court ~~entered~~asserting an ~~order approving the Noteholder RSA.For more information regarding the terms of the Noteholder RSA, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.~~

On October 11, 2019, PG&E Corporation and the Utility entered into debt commitment letters, which were subsequently amended on November 18, 2019, December 20, 2019, January 30, 2020, and February 14, 2020 (as amended, the “Debt Commitment Letters”) with JPMorgan Chase Bank, N.A., Bank of America, N.A., BofA Securities, Inc., Barclays Bank PLC, Citigroup Global Markets Inc., Goldman Sachs Bank USA, Goldman Sachs Lending Partners LLC and the other lenders that may become parties to the Debt Commitment Letters as additional “Commitment Parties” as provided therein (the foregoing parties, collectively, the “Commitment Parties”), 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 (the Utility or any such entity, the “OpCo Borrower”) as borrower thereunder and (b) a $5.0 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 ~~(the~~(PG&E Corporation or any such entity, the “HoldCo Borrower”) as borrower thereunder, subject to the terms and conditions set forth therein. ~~The commitments under the Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier pursuant to the termination rights described below.~~

On March 16, 2020, the Bankruptcy Court approved the Debt Commitment Letters as amended through February ~~28,~~14, 2020. ~~During the three months ended March 31, 2020,~~ PG&E Corporation and the Utility recorded facility fees of ~~$36~~$4 million and ~~$14~~$2 million, respectively, during the three months ended June 30, 2020 and $40 million and $33 million respectively, during the six months ended June 30, 2020, reflected in Reorganization items, net on the Condensed Consolidated ~~Income Statements. In addition,~~Statements of Income. Of the $33 million in cash paid for the Utility’s facility fees, during the six months ended June 30, 2020, the Utility recorded $18 million to a regulatory asset for fees that are deemed probable of recovery.

~~The timing and outcome~~In lieu of entering into the ~~Chapter 11 Cases is uncertain. Although PG&E Corporation,~~Facilities contemplated by the Utility, the Bankruptcy Court, the CPUC and many other stakeholders have stated that they are working towards confirming a plan of reorganization by June 30, 2020, it is possible that the Chapter 11 process could extend beyond the June 30, 2020 deadline and take a number of years to resolve.

In connection with its emergence from Chapter 11 in July 2020, PG&E raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments. For more information, see Note 6 below.

As of March 6, 2020, PG&E Corporation 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”). As a result of PG&E Corporation emerging from Chapter 11 on July 1, 2020, the ~~Ad Hoc Noteholder Committee entered into~~Backstop Commitments were not utilized and terminated in accordance with their terms.

The commitment premium for the ~~Noteholder RSA~~Backstop Commitments was paid in shares of PG&E Corporation’s common stock (with each Backstop Party receiving its pro rata share of 119 million shares of PG&E Corporation’s common stock based on the proportion of the amount of such Backstop Party’s Backstop Commitment to $12.0 billion). PG&E Corporation issued the commitment premium shares to the Backstop Parties on July 1, 2020 in connection with emerging from Chapter 11.

As of June 30, 2020, PG&E Corporation recorded approximately $1.1 billion of expense related to the Backstop Commitment premium in Reorganization items, net. This amount was primarily based on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing price was $9.03 per share and as a result, PG&E Corporation will record an additional $27 million expense in the third quarter of 2020.

Under the Backstop Commitment Letters, PG&E Corporation and the Utility ~~under which it~~have also agreed ~~upon entry~~to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the ~~order of the Bankruptcy Court approving the Noteholder RSA, to withdraw any participation in and support~~aggregate for the ~~Ad Hoc Noteholder Plan, including by taking certain actions~~legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters. As of June 30, 2020, PG&E Corporation recorded $49 million in professional fees and related expenses to ~~defer further action on~~ the make-whole and post-petition interest issues. On February 4, 2020, the Noteholder RSA was approved by the Bankruptcy Court, and on February 5, 2020, the Ad Hoc Noteholder Committee withdrew the Ad Hoc Noteholder Plan. It is possible that, if the Noteholder RSA is terminated, the Ad Hoc Noteholder Committee could re-file a competing plan with similar or different terms.Backstop parties in Reorganization items, net.

~~Debtor-In-Possession Financing~~In connection with PG&E Corporation’s underwritten offerings of up to $5.75 billion of equity securities to finance the transactions contemplated by the Plan (the “Offerings”), up to $523 million (the “Option Amount”) was issuable pursuant to customary options granted to the underwriters thereof to purchase additional securities (the “Option Securities”).

~~See Note 5 for further discussion~~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 provides that, subject to certain conditions, the Backstop Party will purchase on the Effective Date, and receive on the Settlement Date (as defined in each Forward Stock Purchase Agreement) an amount of common stock of PG&E Corporation equal to its pro rata share of the ~~DIP Facilities,~~value of the Option Securities which ~~provide up~~is approximately $523 million (such amount, each Backstop Party’s “Greenshoe Backstop Purchase Amount”), at a price per share equal to ~~$5.5 billion~~the lesser of (i) the lowest per share price of common stock sold on an underwritten basis to the public in ~~financing.~~an offering of common stock of PG&E Corporation, as disclosed on the cover page of the 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 is $9.50 per share. Each Forward Stock Purchase Agreement expires on the later of (x) 30 days from June 25, 2020 and (y) the latest settlement date for the sale of Option Securities to the underwriters.

On June 25, 2020, the Backstop Parties funded the Greenshoe Backstop Purchase Amount to PG&E Corporation in the amount of $523 million which is recorded in Other current liabilities on the Condensed Consolidated Financial Statements. As of June 30, 2020, no portion of the Greenshoe Backstop Purchase Amount had been settled or redeemed. 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 will redeem $120.5 million of the 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. On August 3, 2020, PG&E Corporation will deliver 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 will not be redeemed.

Additionally, each Forward Stock Purchase Agreement provides that, subject to the consummation by PG&E Corporation of the Offerings, PG&E Corporation will 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. As of June 30, 2020, PG&E Corporation recorded $444 million of expense related to the Additional Backstop Premium Shares in Reorganization items, 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 Effective Date, PG&E Corporation’s closing stock price was $9.03 per share and as a result, PG&E Corporation will record an additional $8 million expense in the third quarter of 2020.

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 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~~subject to an injunction and will be satisfied pursuant to the Plan and the ~~Utility continue business operations as debtors-in-possession.~~Chapter 11 claims reconciliation process. 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 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.~~were subject to an injunction and will be satisfied pursuant to the Plan and the Chapter 11 claims reconciliation process. Although payment of pre-petition claims outside of the Plan generally is not permitted, the Bankruptcy Court granted PG&E Corporation and the Utility authority to pay certain pre-petition 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.

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,~~negotiations with creditors. As of June 30, 2020, such amounts have been reclassified to current or non-current liabilities in the ~~values~~Condensed Consolidated Balance Sheets, based upon management’s judgment as to the timing for settlement of ~~any collateral securing~~ such ~~claims, rejection of executory contracts, continued reconciliation or other events.~~liabilities.

~~The following table presents LSTC~~Liabilities subject to compromise as ~~reported in~~of December 31, 2019 which were settled or reclassified during the ~~Condensed Consolidated Balance Sheets at March 31, 2020:~~six months ended June 30, 2020 consist of the following:

PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition Date. PG&E Corporation and the Utility continue their review and analysis of certain 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 ~~in liabilities subject to compromise.~~amounts. To the extent that ~~PG&E Corporation and the Utility believe that~~ such claims ~~will be~~were allowed by the Bankruptcy Court, PG&E Corporation and the Utility ~~will continue to record~~has recorded the ~~expected~~ allowed amounts of such claims ~~as liabilities subject~~until such claims are paid in accordance with the Plan and the Confirmation Order.

On the Effective Date, pursuant to ~~compromise. The determination~~the Plan, 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 for fiscal year 2020 to be paid on or before January 15, 2021 (the “First Payment Date”) and (ii) of the ~~expected allowed amount~~remainder of ~~a claim is based~~$1.35 billion of Tax Benefits for fiscal year 2021 to be paid on ~~many factors, including whether~~or before January 15, 2022.

Also on the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the 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, orno par value (the “Common Stock”). As a result of the ~~Utility is party~~Equity Units Underwriters exercising their option to ~~a settlement~~purchase 1.45 million additional Equity Units, on August 3, 2020, PG&E Corporation will deliver 748,415 additional shares of Common Stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with ~~applicable claimholders or their representatives, and is necessarily limited to information available to PG&E Corporation and~~ the ~~Utility. Claims covered by a settlement agreement include wildfire-related claims and Utility debt claims. See “Restructuring Support Agreement with~~Fire Victim Trust.

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

⁽¹⁾The Plan, however, provides that the holders of certain claims may pursue their claims against PG&E Corporation ~~amounts reflected under~~and the ~~column “PG&E Corporation” exclude~~Utility on or after the ~~accounts of the Utility.~~

Furthermore, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy ~~Court granted~~Code to pursue, or continue to pursue, their claims against PG&E ~~Corporation’s~~Corporation and the ~~Utility’s motion for declaratory judgment in an adversary proceeding entitled Pacific Gas and Electric Company v. FERC. In its amended declaratory judgment,~~Utility on or after the Bankruptcy Court found that FERC had no “concurrent jurisdiction, or any jurisdiction, over the determination of whether any rejections of power purchase contracts by either Debtor should be authorized” pursuant to section 365 of the Bankruptcy Code. The Bankruptcy Court also found that the “Debtors do not need approval from the Federal Energy Regulatory Commission to reject any of their power purchase contracts” and that “[a]ny determinations of the Federal Energy Regulatory Commission” that were contrary to these findings “are void, of no force and effect and not binding on this court or either Debtor.” The Bankruptcy Court further stated that such determinations include,Effective Date, including but ~~are~~ not limited to, ~~those previously made~~claims arising from or relating to:

In addition, claims continue to be pursued against PG&E Corporation and the Utility and certain ~~FERC proceedings initiated before the Chapter 11 Cases were filed~~of their respective current and former directors and officers as well as certain underwriters, in connection with ~~power purchase contracts with~~3 purported securities class actions, as further described in Note 10 under the ~~Utility (the “FERC Orders”).~~

The Plan ~~proposes to assume~~assumed all power purchase agreements and community choice aggregation servicing agreements.

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,~~June 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,~~June 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 six months ended ~~March 31,~~June 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. PG&E Corporation and the Utility will 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. At June 30, 2020, PG&E Corporation and the Utility satisfied the eligibility and other requirements set forth in AB 1054 and as a result, upon payment of the initial contribution on the Effective Date, the Wildfire Fund is available to pay for eligible claims arising as of the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising as of the effective date of AB 1054 and the Utility’s emergence from Chapter 11, 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. Therefore, PG&E Corporation and the Utility have 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 are non-current, called “Wildfire fund asset” in the Condensed Consolidated Balance Sheets. On June 30, 2020, the Utility recorded amortization expense of $173 million related to the coverage received from the effective date of AB 1054 to June 30, 2020. 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. 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 used a Monte Carlo simulation based on twelve years of historical data from wildfires caused by electrical equipment to estimate expected loss. The assumptions create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The most significant assumption is the 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. PG&E Corporation and the Utility utilize historical, publicly available fire-loss data as a starting point; however, future fire-loss can be difficult to estimate due to uncertainties around the impacts of climate change, land use changes, and mitigation efforts by the California electric utility companies.

Other assumptions 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 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 will 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. 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 June 30, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset.

42

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.

On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities (as defined in the DIP Credit Agreement), 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 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 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.

On January 29, 2020, the Utility borrowed $500 million under the DIP Delayed Draw Term Loan Facility.

~~The commencement of~~On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of the debt outstanding under or in respect of, certain instruments and agreements relating to direct financial obligations of PG&E Corporation and the Utility (the “Accelerated Direct Financial Obligations”). However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of 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 PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.11.

The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at ~~March 31,~~June 30, 2020:

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 ~~December 2021, subject~~an escrow agreement by and among the Escrow Agent and the Utility. As of June 30, 2020, the $8.925 billion of proceeds were included in restricted cash on the Condensed Consolidated Balance Sheets. 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 $11.9 billion of its first mortgage bonds (the “New Mortgage Bonds”) in satisfaction of certain ~~terms and conditions, including payment~~of its pre-petition senior unsecured debt, as described in the table below.

On the Effective Date, pursuant to the Plan, the Utility reinstated $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 ~~25 basis point extension fee.~~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 below.

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “Term Loan”) under a term loan credit 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. As of June 30, 2020, the $2.75 billion of proceeds were included in restricted cash on the Condensed Consolidated Balance Sheets.

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 will bear 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 1.00% 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) other fundamental changes. 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.

As of ~~March 31,~~June 30, 2020, ~~PG&E~~the $2.0 billion of proceeds were included in restricted cash on the Condensed Consolidated Balance Sheets. 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 ~~each had 0 commercial paper borrowings outstanding.~~in accordance with the terms and conditions contained in the Plan. The Notes are secured by a pledge of PG&E ~~Corporation and the Utility do not expect to be able to access the commercial paper market for the duration~~Corporation’s ownership interest in 100% of the ~~Chapter 11 Cases.~~

The following table summarizes PG&E Corporation’s and the Utility’s ~~outstanding debt subject to compromise:~~debt:

On May 26, 2020, the Utility entered into (i) a commitment letter (the “Utility RCF Commitment Letter”) with JPM and ~~Debt Commitments Letters” in Note 2~~other commitment parties thereto (the “Utility RCF Commitment Parties”) pursuant to which the Utility RCF Commitment Parties agreed, subject to the terms and satisfaction or waiver of the ~~Condensed Consolidated Financial Statements above for discussion~~conditions contained therein, to provide a $3.5 billion revolving credit facility (the “Utility Revolving Credit Facility”) to the Utility and (ii) a commitment letter (the “Utility Term Loan Commitment Letter”) with JPM and the other commitment parties thereto (the “Utility Term Loan Commitment Parties”) pursuant to which the Utility Term Loan Commitment Parties agreed, subject to the terms and satisfaction or waiver of the conditions contained therein, to provide an up to $3.0 billion term loan credit facility (the “Utility Term Loan Credit Facility,” as amended on June 19, 2020) to the Utility.

Borrowings under the Utility Revolving Credit Agreement will 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 Agreement, 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 Agreement 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 Agreement.

The Utility Revolving Credit Agreement 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) other fundamental changes. In addition, the Utility Revolving Credit Agreement will require that the Utility maintain a ratio of total consolidated debt ~~commitments.~~to consolidated capitalization of at most 65% as of the end of each fiscal quarter.

In the event of a default by the Utility under the Utility Revolving Credit Agreement, 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, shall), declare the amounts outstanding under the Utility Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Revolving Credit Agreement become payable immediately.

The Utility may voluntarily repay outstanding loans under the Utility Revolving Credit Agreement 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 Agreement.

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 Agreement”) with JPM, as administrative agent, the other lenders from time to time party thereto as contemplated by the Utility Term Loan Commitment Letter. 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 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the 18-Month Term Loan Facility is January 1, 2022.

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

The Utility Term Loan Credit Agreement 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, and 4) other fundamental changes. In addition, the Utility Term Loan Credit Agreement will require that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of at most 65% as of the end of each fiscal quarter.

In the event of a default by the Utility under the Utility Term Loan Credit Agreement, 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 Agreement, 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 Agreement become payable immediately.

The Utility is required to prepay outstanding term loans under the Utility Term Loan Credit Agreement (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 Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans.

On May 26, 2020, PG&E Corporation entered into a commitment letter (the “Corporation RCF Commitment Letter”) with respect to a $500 million revolving credit facility (the “Corporation Revolving Credit Facility”), which was executed on July 1, 2020.

Borrowings under the Corporation Revolving Credit Agreement will 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 Agreement, 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 Agreement 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 Agreement 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 and (10) other fundamental changes. 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 at most 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 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 Corporation Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Corporation Revolving Credit Agreement become payable immediately.

PG&E Corporation may voluntarily repay outstanding loans under the Corporation Revolving Credit Agreement 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 Agreement.

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 June 22, 2020, PG&E Corporation filed the Amended Articles with the Secretary of State of California which increased the authorized number of shares of common stock to 3.6 billion and the authorized number of shares of preferred stock to 400 million.

In connection with emergence from Chapter 11, in July 2020, PG&E Corporation raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments as described below.

On June 7, 2020, PG&E Corporation entered into an Investment Agreement (the “Investment Agreement”) with certain investors relating to the issuance and sale to the investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock. Per the Investment Agreement, the price per share was equal to $9.50 per share, which was the public equity offering price in the Common Stock Offering.

On July 1, 2020, pursuant to the terms of the Investment Agreement, PG&E Corporation issued to the investors 342.1 million shares of common stock. Each investor will be subject to certain transfer restrictions, including that such investor will be restricted from transferring any shares of Common Stock purchased pursuant to the Investment Agreement (such shares, “Shares”) or engaging in hedging transactions with respect to the Shares, until the 90-day anniversary of the Effective Date, subject to certain exceptions. The investors and their affiliates will have certain customary registration rights with respect to the Shares held by such investor pursuant to the terms of the Investment Agreement.

On June 25, 2020, PG&E Corporation priced (i) an offering of 423.4 million shares of its common stock (the “Common Stock Offering”), and (ii) a concurrent offering of 14.5 million of its equity units (the “Equity Units”), for total net proceeds to PG&E Corporation, after deducting the underwriting discounts and before estimated offering expenses payable by the PG&E Corporation, of $3.97 billion and $1.19 billion, respectively. The Common Stock Offering and the concurrent offering of Equity Units are referred as the “Equity Offerings.”

On June 25, 2020, in connection with the Common Stock Offering, the Corporation entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of several underwriters named in the Common Stock Underwriting Agreement (the “Common Stock Underwriters”), pursuant to which the Corporation agreed to issue and sell 423.4 million shares of its common stock to the Common Stock Underwriters. In addition, on June 25, 2020, the Corporation entered into an underwriting agreement (the “Equity Units Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Equity Units Underwriting Agreement (the “Equity Units Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 14.5 million prepaid forward stock purchase contracts (the “Purchase Contracts”) to the Equity Underwriters in order for the Equity Units Underwriters to sell 14.5 million Equity Units. The prepaid forward stock purchase contract portion of the Equity Units offered represent the right to receive, on maturity, between 125 million and 153 million shares of PG&E Corporation common stock, subject to certain adjustments as provided therein.

In connection with the Common Stock Offering and pursuant to the Common Stock Underwriting Agreement, PG&E Corporation granted the underwriters a 30-day option to purchase up to an additional 42.3 million shares of common stock. In addition, in connection with the Equity Units Offering and pursuant to the Equity Units Underwriting Agreement, the Corporation also granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.45 million Purchase Contracts to be used by the Equity Units Underwriters to create up to an additional 1.45 million Equity Units (together with the 42.3 million shares of common stock, the “Option Securities”).

See “Plan of Reorganization, and Restructuring Support Agreements, Equity Backstop Commitments and Forward Stock Purchase Agreements and Debt Commitment Letters” in Note 2 above for discussion of the equity backstop commitments which resulted in total net proceeds of $523 million.

On the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust, pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477 million shares of common stock of PG&E Corporation, no par value. 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 will deliver 748,415 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.

On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash, along with the Fire Victim Trust Shares, to the Utility, which used the funds and shares to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan and transferred the Fire Victim Trust Shares to the Fire Victim Trust as described above. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions described herein.

Under Section 382 of the Internal Revenue Code (IRC), if a corporation (or a consolidated group) undergoes an “ownership change,” and the corporation does not qualify for (or elects out of) the special bankruptcy exception in Section 382(l)(5) of the Internal Revenue Code, such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally 5% shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. The calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.

As of the Effective Date, PG&E Corporation does not believe that it has undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.

In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility paid to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock. Because of the price of the stock on the date of transfer, the shares transferred to the Fire Victim Trust were valued at $4.53 billion, $2.22 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust.

In addition, this deferred tax asset reflects PG&E Corporation’s conclusion as of June 30, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a “grantor trust,” but only if PG&E Corporation receives favorable determinations from the IRS regarding certain aspects of such election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur instead at the time the Fire Victim Trust pays the fire victims and will be based on the price at which the Fire Victim Trust sells the shares. In this case, the accounting treatment will require a re-evaluation under applicable accounting guidance of the remaining deferred tax asset and could result in a further impairment thereof or other material impact on the Condensed Consolidated Financial Statements. Additionally, the value of the deduction may be materially different than the value of the deduction if the Fire Victim Trust is treated as a “qualified settlement fund.”

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 forgoing 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 at most 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.

PG&E Corporation and the Utility do not expect to commence payment of dividends on its common or preferred stock upon emergence from Chapter 11.

On July 23, 2020, PG&E Corporation sent a notice of 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 six months ended June 30, 2020, there were 0 issuances under ~~the PG&E Corporation February 2017 equity distribution agreement for the three months ended March 31, 2020.~~this agreement.

Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

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

For each of the periods, ~~presented above,~~all potentially dilutive securities were excluded from the calculation of outstanding common shares on a diluted basis ~~excluded an insignificant amount~~as PG&E Corporation has incurred a net loss for each period presented.

Following its emergence from Chapter 11, PG&E Corporation began raising funds through the issuance of ~~options and securities that were antidilutive.~~equity. These issuances will materially impact the calculation of EPS in future periods. For more information on equity issuances see Note 6: Equity, above.

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. By order dated April 8, 2019, the Bankruptcy Court authorized the Utility to continue these programs in the ordinary course of business in a manner consistent with its pre-petition practices.

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

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

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

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

At ~~March 31,~~June 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, multiple credit rating agencies downgraded the Utility’s company credit ratings below investment grade, which resulted in the Utility posting additional collateral. As of ~~March 31,~~June 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 six months ended ~~March 31,~~June 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.

The Equity Backstop Commitments and Forward Stock Purchase Agreements are defined as financial instruments with both the Backstop Premium Shares and the Additional Backstop Premium Shares measurable at fair value on each reporting period. PG&E Corporation used ~~both~~ market observable inputs ~~and unobservable data~~ to derive the fair value as of the reporting date. ~~The Backstop Commitments 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 six months ended ~~March 31,~~June 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,~~June 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.

See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorney’s Office Investigations” below for more information on the 2015 Butte fire.

According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s 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 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

As described below under the heading “Restructuring Support Agreement with the TCC,” on December 6, 2019, PG&E Corporation and the Utility entered into a RSA with the TCC, the Consenting Fire Claimant Professionals and the Shareholder Proponents to potentially resolve all wildfire-related claims relating to the 2017 Northern California wildfires and the 2018 Camp fire (other than subrogated insurance claims and Public Entity Wildfire Claims) through the Chapter 11 process. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA.

As described below under the heading “Restructuring Support Agreement with Holders of Subrogation Claims,” on September 22, 2019, PG&E Corporation and the Utility entered into a RSA with certain holders of insurance subrogation claims to potentially resolve all insurance subrogation claims relating to the 2017 Northern California wildfires and the 2018 Camp fire through the Chapter 11 process. On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA.

As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process. The PSAs do not require Bankruptcy Court approval to be effective; however, Bankruptcy Court approval of the Plan that incorporates the terms of the PSAs was required. The Bankruptcy Court confirmed the Plan on June 20, 2020.

On April 21, 2020, the parties announced that settlement agreements had been reached with certain Federal agencies (including FEMA and the United States Small Business Administration (the “SBA”)) and certain State agencies (including Cal OES and Cal Fire) regarding their claims filed against PG&E Corporation or the Utility in the Chapter 11 Cases which constitute “Fire Claims” (as defined in the Plan). Pursuant to the terms of the settlement agreements:

PG&E Corporation and the Utility filed a motion seeking Bankruptcy Court approval of the settlement agreements on April 26, 2020, and the Bankruptcy Court approved the settlement agreements on May 18, 2020.

Pre-petition wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

At ~~March 31,~~June 30, 2020 and December 31, 2019, the Utility’s Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims of $25.5 billion. The aggregate liability of $25.5 billion for claims in connection 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 pursuant to the Subrogation RSA, plus (ii) $47.5 million for expected professional fees for professionals retained by subrogated insurance claimholders to be reimbursed pursuant to the Subrogation RSA, plus (iii) $1 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs, plus (iv) $13.5 billion for all other wildfire-related claims, including individual wildfire claimholders (including those with uninsured and underinsured property losses) and clean-up and fire suppression costs, pursuant to the TCC RSA. The aggregate liability of $25.5 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire ~~corresponds~~corresponded PG&E Corporation’s and the Utility’s best estimate of probable ~~losses~~losses.

On July 1, 2020, pursuant to the Plan, PG&E Corporation and ~~is subject~~the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to ~~change based~~be funded on ~~additional information, including~~a deferred basis), 477.0 million shares of common stock of PG&E Corporation (representing 22.19% of the ~~other factors discussed below. (See “2018 Camp~~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. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire ~~2017 Northern California Wildfires~~Victim Claims (as defined in the Plan) have been satisfied, released and ~~2015 Butte~~discharged and channeled to the Fire ~~Accounting Charge” below.)~~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 will be 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 “Chapter 11 Claims Process.”

On July 1, 2020, PG&E Corporation and the ~~Petition Date,~~Utility funded the Subrogation Wildfire Trust for the benefit of insurance subrogation claimants 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 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 ~~wildfire-related~~insurance subrogation claims ~~were classified as LSTC~~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 subrogated insurance claims and $47.5 million liability for professional fees will be 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 used to reimburse the Settling Public Entities for any and all ~~pending litigation was stayed.~~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 Public Entity Wildfire Claims have been satisfied, released and discharged. Accordingly, the $1.0 billion liability for Public Entity Wildfire Claims will be extinguished in the third quarter of 2020.

In addition, during the three and six months ended June 30, 2020, the Utility incurred legal and other costs of ~~$34~~$24 million and ~~$47~~$58 million, respectively, related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire, as compared to $26 million and $73 million, respectively, during the ~~quarters~~same periods in 2019. During the three and six months ended ~~March 31,~~June 30, 2020, ~~and 2019, respectively.~~

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 Plan in order to 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”). ~~PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or groups of public entities, as applicable:~~

•the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”);

~~The “Settlement Amount” set forth~~These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in “Chapter 11 Claims Process” above, the actions required by each PSA ~~is as follows:~~

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 (the “Aggregate Subrogation Recovery”) to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to 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 professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.

The Subrogation RSA provides that, subject to certain terms and conditions (including that PG&E Corporation and the Utility remain solvent), the Consenting Subrogation Creditors will support the Plan with respect to its treatment of the Subrogation Claims, including by voting their Subrogation Claims to accept the Plan in the Chapter 11 Cases.

On December 6, 2019, PG&E Corporation and the Utility entered into ~~a Restructuring Support Agreement, which was subsequently amended on December 16, 2019, with~~ the TCC ~~the Consenting Fire Claimant Professionals and the Shareholder Proponents (as amended, the “TCC RSA”).~~RSA. The TCC RSA provides for, among other things, ~~an aggregate~~a combination of ~~$13.5 billion in value~~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 is to be funded into ~~a trust (the “Fire~~the Fire Victim ~~Trust”)~~Trust to be established pursuant to the Plan for the benefit of holders of the Fire Victim Claims ~~and~~ will consist of (a) $5.4 billion in cash to be contributed on the ~~effective date~~Effective Date of the Plan, (b) $1.35 billion in cash ~~comprising~~consisting of (i) $650 million to be paid in cash on or before January 15, 2021 and (ii) ~~$700 million~~the remaining balance of $1.35 billion to be paid in cash on or before January 15, 2022, ~~subject~~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) ~~$6.75 billion in~~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 will 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~~Effective Date of the Plan, assuming the Utility’s ~~current~~ allowed ~~ROE.~~ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the 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 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 ~~and 2016~~ insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted ~~prior~~ to ~~the Petition Date.~~

Pursuant to further discussions with claimants relating to the Ghost Ship fire, certain provisions of 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 arising out of the Ghost Ship fire will be resolved separately from the TCC RSA.

~~2015 Butte Fire~~

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.

67

~~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 reviewing the ~~Utility are cooperating with those investigations.~~ matter.

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 or fines 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 of at least $600 million in connection with the 2019 Kincade ~~fire. If PG&E Corporation and the Utility were to incur a loss in respect of the 2019 Kincade~~ fire ~~PG&E Corporation and the Utility estimate that the amount of such loss could exceed $600 million~~ (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 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, 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.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $600 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 PG&E Corporation~~recovery will occur, and the Utility ~~to believe that a loss is probable, resulting in the accrual of a liability at that time,~~can reasonably estimate the amount or its range. As of ~~which could be significant and may exceed~~June 30, 2020, the ~~foregoing estimate~~Utility has recorded an insurance receivable for the full amount of the lower end of the range of reasonably possible losses. For the reasons discussed above, the 2019 Kincade fire 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$430 million. While the Utility plans to ~~participate in~~seek recovery of all insured losses, it is unable to predict the ~~Wildfire Fund.~~ultimate amount and timing of such insurance recoveries.

PG&E Corporation and the Utility have received and are responding 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.

68As of July 24, 2020, PG&E Corporation and the Utility are aware of 3 complaints on behalf of approximately 142 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.

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,~~June 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,~~June 30, 2020, the Utility expected to recover ~~$1,029~~$1,030 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~~$222 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~~$503 million if the extent of contamination or necessary remediation 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~~$66 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 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.

~~In 2018,~~ PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general wildfire liability in policies covering wildfire and non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for wildfire property damages only, which included approximately $200 million of coverage through the use of a catastrophe bond. In 2020, PG&E Corporation and the Utility hashave liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period offrom August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period offrom August 1, 2019 through July 31, 2020 and $480 million for the period offrom September 3, 2019 through September 2, 2020. PG&E Corporation and the Utility continue to pursue additional insurance coverage. Various coverage limitations applicable to different insurance layers could result in uninsured costs in the future depending on the amount and type of damages resulting from covered events.

In July 2020, the Utility ~~recovered~~renewed its liability insurance coverage for wildfire events in ~~rates during the year ended December 31, 2019. The Utility has sought recovery of certain premium costs paid in excess of~~ the amount of $757.5 million (subject to an initial self-insured retention of $60 million), comprised of $715 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility ~~currently~~renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is ~~recovering~~approximately $749 million. PG&E Corporation and the Utility continue to pursue additional insurance coverage for the period from ~~customers~~August 1, 2020 through July 31, 2021.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the ~~GRC period ended December 31, 2019.~~ future depending on the amount and type of damages resulting from covered events.

The Utility’s 2020 GRC settlement agreement, currently pending before the Commission, includes a new two-way balancing account that, if approved, would allow the Utility to ~~pass through~~recover in rates its actual insurance premium costs for up to $1.4 billion in coverage. The Utility is unable to predict the timing and outcome of the 2020 GRC proceeding.

~~PG&E Corporation~~The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any calendar year that do not exceed the greater of $1.0 billion in the aggregate and the ~~Utility record a receivable for~~amount of insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through March 31, 2020, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $843 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrencecoverage required under ~~the insurance policies.~~AB 1054.

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,~~June 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 Effective Date, PG&E Corporation and Subsidiaries does not believe that ~~the Chapter 11 Cases resulted in~~it has undergone an ownership change, and therefore, its net operating loss ~~of or limitation on the utilization of any~~carryforwards and other tax attributes are not limited by IRC 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 approved AB 85 to increase 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.

See “Ownership Restrictions in PG&E Corporation 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.

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, 2019, the Utility had undiscounted future expected obligations of approximately $38 billion. (See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.) ~~The~~

On June 5, 2020, the Utility ~~has not~~ entered into ~~any new material commitments during~~an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the ~~three months ended March 31,~~Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Building (as defined below) by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at 300 Lakeside Drive, Oakland, California 94612 (the “Building”) to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.

The term of the Lease will begin on or about January 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.

The Lease will require the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Building to create a separate legal parcel that contains the Building (the “Property”) that can be sold to the Utility. The Lease will grant to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023. The Utility expects that the annual lease costs and the capital costs associated with the purchase option will be eligible for cost recovery through one or more future proceedings at the CPUC, including in the 2023 General Rate Case. In addition, in accordance with and subject to the terms of the Agreement and the Lease Agreement, respectively, the Utility would issue (i) an option payment letter of credit in the amount of $75 million on or before the Lease Date (as defined in the Agreement and the Lease Agreement), and (ii) and a lease security letter of credit in the amount of $75 million concurrently with the execution and delivery of the Lease Agreement.

In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SF General Office”). Any sale of the SF General Office would be subject to approval by the CPUC.

At June 30, 2020, the Agreement had no impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

The Plan became effective and PG&E Corporation and the Utility emerged from Chapter 11 on July 1, 2020. Several transactions related to PG&E Corporation’s and the Utility’s emergence from Chapter 11 occurred after June 30, 2020, including on July 1, 2020 and thereafter. For disclosure of such subsequent events, please see the Notes to these Condensed Consolidated Financial Statements above.

On July 27, 2020, Elliott Management Corporation, a Consenting Noteholder, filed a motion with the Bankruptcy Court asserting an approximately $250 million administrative claim against PG&E Corporation and the Utility, alleging that PG&E Corporation and the Utility breached the Noteholder RSA by failing to use their best efforts to cause Backstop Parties to transfer up to $2.0 billion of Backstop Commitments to certain of the Consenting Noteholders. Objections to the motion are due on August 11, 2020, and a hearing on the motion is scheduled for August 25, 2020. PG&E Corporation and the Utility are unable to predict the timing and outcome of this proceeding.

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 regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this Form 10-Q. It also should be read in conjunction with the 2019 Form 10-K.

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation’s and the Utility’s Chapter 11 Cases ~~are being~~were jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). On the Effective Date, PG&E Corporation and the Utility emerged from Chapter 11. For additional information regarding the Chapter 11 Cases, refer to the website maintained by Prime Clerk, LLC, PG&E Corporation’s and the Utility’s claims and noticing agent, at http://restructuring.primeclerk.com/pge. The contents of this website are not incorporated into this document.

For more information about ~~the~~ Chapter 11 ~~Cases,~~emergence and related transactions, see ~~“Item 1A. Risk Factors – Risks Related to Chapter 11 Proceedings and Liquidity” and “Item 7. MD&A – Chapter 11 Proceedings” in the 2019 Form 10-K and Notes 2 and 5 of~~ the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

The accompanying Condensed Consolidated Financial Statements ~~to this Form 10-Q~~ 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,~~ 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. As a result of these challenges, such realization of assets and satisfaction of liabilities are subject to uncertainty. For more information about the 2018 Camp fire and 2017 Northern California wildfires, seeprotection (see Note 10 of the Notes to the Condensed Consolidated Financial Statements ~~and the 2019 Form 10-K.~~

For more information about ~~these matters,~~Chapter 11 emergence and related transactions, see the Notes ~~1 and 2~~ to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

Under Section 382 of the Internal Revenue Code (IRC), if a corporation (or a consolidated group) undergoes an “ownership change,” and the corporation does not qualify for (or elects out of) the special bankruptcy exception in Section 382(l)(5) of the Internal Revenue Code, such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally 5% shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. As discussed in the Risk Factors section below, the calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.

As of the Effective Date, PG&E Corporation does not believe that it has undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.

In 2019, ~~Form 10-K.~~$6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility paid to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock. Because of the price of the stock on the date of transfer, the shares transferred to the Fire Victim Trust were valued at $4.53 billion, $2.22 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust.

In addition, this deferred tax asset reflects PG&E Corporation’s conclusion as of June 30, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. As discussed further below in the Risk Factors section, PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a “grantor trust,” but only if PG&E Corporation receives favorable determinations from the IRS regarding certain aspects of such election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur instead at the time the Fire Victim Trust pays the fire victims and will be based on the price at which the Fire Victim Trust sells the shares. In this case, the accounting treatment will require a re-evaluation under applicable accounting guidance of the remaining deferred tax asset and could result in a further impairment thereof or other material impact on the Condensed Consolidated Financial Statements. Additionally, the value of the deduction may be materially different than the value of the deduction if the Fire Victim Trust is treated as a “qualified settlement fund.”

PG&E Corporation’s net ~~income available for~~loss attributable to common shareholders was ~~$371~~$1,972 million and $1,601 million in the three and six months ended ~~March 31,~~June 30, 2020, respectively, compared to ~~$136~~net losses of $2,553 million and $2,420 million in the same ~~period~~periods in 2019. InPG&E Corporation recognized charges of $1.9 billion and $2.0 billion, net of probable insurance recoveries, associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three and six months ended ~~March 31,~~June 30, 2019, as compared to a charge of $170 million, net of probable insurance recoveries related to the 2019 Kincade fire in the three and six months ended June 30, 2020. Additionally, in the three and six months ended June 30, 2020, PG&E Corporation recognized ~~additional base revenues authorized in the TO20 rate case, as compared~~$1.1 billion of expense related to the Backstop Commitment premium and $444 million of expense related to the Additional Backstop Premium Shares, with no similar amounts for the same ~~period~~periods in 2019.

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see “Item 1A. Risk Factors” in this Form 10-Q and the 2019 Form 10-K. In addition, this quarterly 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. See the section entitled “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are unable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of net income (loss) attributable to common shareholders for the three and six months ended ~~March 31,~~June 30, 2020 and 2019:

PG&E Corporation’s net income (loss) primarily consists of income taxes, interest income on cash held, interest expense on long-term debt, reorganization items, net, and ~~reorganization items.~~approximately $1.5 billion in expense related to the Backstop Commitment premium and 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 six months ended ~~March 31,~~June 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.

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

The following discussion presents the Utility’s operating results for the three and six months ended ~~March 31,~~June 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~~$471 million, or ~~12%~~18%, and $783 million, or 15%, in the three and six months ended ~~March 31,~~June 30, 2020, respectively, compared to the same ~~period~~periods in 2019, primarily due to additional ~~revenues~~revenue recorded pursuant to the pending TO20 rate case.

The Utility’s operating and maintenance expenses that impacted earnings decreased by ~~$231~~$34 million or ~~14%,~~2% in the three months ended ~~March 31,~~June 30, 2020, compared to the same period in 2019, due to a decrease in costs relating to enhanced and accelerated inspections and repairs of transmission and distribution assets of approximately $270 million in the three months ended June 30, 2020, compared to the same period in 2019. In addition, clean-up and repair costs relating to the 2018 Camp fire decreased by $71 million in the three months ended June 30, 2020, compared to the same period in 2019. These decreases were partially offset by $35 million in clean-up and repair costs related to the 2019 Kincade fire, $45 million in costs related to the Wildfire OII settlement, as modified by the Decision Different, and increased labor and insurance costs in the three months ended June 30, 2020, compared to the same period in 2019.

The Utility’s operating and maintenance expenses that impacted earnings decreased by $197 million, or 6%, in the six months ended June 30, 2020, compared to the same period in 2019, primarily due to a decrease in costs relating to enhanced and accelerated inspections and repairs of ~~$198~~transmission and distribution assets of approximately $470 million ~~related~~in the six months ended June 30, 2020, compared to ~~electric asset inspections costs. Additionally,~~the same period in 2019. In addition, clean-up and repair costs relating to the 2018 Camp fire decreased by ~~$166~~$250 million asin the six months ended June 30, 2020, compared to the same period in ~~2019 (the Utility recorded $13~~2019. These decreases were partially offset by $20 million in restoration and rebuild costs related to the ~~three months ended March 31, 2020 for~~2018 Camp fire, $35 million in clean-up and repair costs related to the ~~2018 Camp~~2019 Kincade fire, $61 million in costs related to the Wildfire OII settlement, as modified by the Decision Different, and increased labor, contract, insurance, and benefits costs in the six months ended June 30, 2020, compared to ~~$179 million in~~the same period in ~~2019). These decreases were partially offset~~2019.

Cost related to wildfires that impacted earnings decreased by ~~$43~~$3.7 billion, or 96%, in the three and six months ended June 30, 2020, compared to the same periods in 2019. The Utility recognized pre-tax charges of $600 million ~~for clean-up and repair costs relating~~related to the 2019 Kincade fire, ~~incurred~~partially offset by $430 million in insurance recoveries for the three and six months ended June 30, 2020, compared to pre-tax charges of $1.9 billion and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three and six months ended June 30, 2019.

(See “Item 1A. Risk Factors” in the 2019 Form 10-K, as updated in “Item 1A. Risk Factors” in this Form 10-Q, and Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Wildfire fund expense that impacted earnings increased by $173 million, or 100%, in the three and six months ended June 30, 2020, compared to the same periods in 2019. During the three months ended ~~March 31,~~June 30, 2020, the Utility satisfied the eligibility and other requirements set forth in AB 1054 and as a result, recorded amortization expense related to the Wildfire Fund coverage received from the effective date of AB 1054 to June 30, 2020.

92(See Notes 3 and 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by ~~$58~~$78 million, or 7%10%, and $136 million, or 9%, in the three and six months ended ~~March 31,~~June 30, 2020, respectively, compared to the same ~~period~~periods in 2019, primarily due to capital additions and an increase in depreciation rates associated with the 2019 GT&S rate case.

There was no material change to interest income that impacted earnings for the periods presented.

Interest expense that impacted earnings increased by ~~$151~~$129 million, or ~~150%~~215%, and $280 million, or 174%, in the three and six months ended ~~March 31,~~June 30, 2020, respectively, compared to the same ~~period~~periods in 2019, primarily due to the cessation of interest accruals on outstanding pre-petition debt in ~~the three months ended March 31,~~ 2019 in connection with the Chapter 11 Cases. In the fourth quarter of 2019, the Utility concluded that interest was probable of being an allowed claim and resumed recording interest on pre-petition debt subject to compromise.

Other income, net increased by ~~$27~~$29 million, or ~~123%~~145%, and $56 million or 137%, in the three and six months ended ~~March 31,~~June 30, 2020, respectively, compared to the same ~~period~~periods in 2019, primarily due to lower pension expense resulting from higher than expected return on plan assets.

Reorganization items, net ~~decreased~~increased by ~~$18~~$54 million, or ~~16%,~~95% in the three months ended ~~March 31,~~June 30, 2020 compared to the same period in 2019 primarily due to ~~a $94~~an increase of $34 million ~~charge recorded in 2019 related to DIP facilities costs, offset by a $72 million increase in~~of expenses directly associated with the Utility’s Chapter 11 ~~filing.~~filing and a decrease in interest income of $18 million.

Reorganization items, net increased by $36 million, or 21% in the six months ended June 30, 2020, compared to the same period in 2019 primarily due to an increase of $107 million of expenses directly associated with the Utility’s Chapter 11 filing and a decrease in interest income of $22 million, offset by a decrease in DIP financing costs of $94 million.

(See “Item 1A. Risk Factors” in the 2019 Form 10-K and Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Income tax benefit decreased by ~~$56 million,~~$1.68 billion, or ~~65%~~150%, and $1.73 billion, or 144%, in the three and six months ended ~~March 31,~~June 30, 2020, respectively, as compared to the same ~~period~~periods in ~~2019. The effective tax rates for the three months ended March 31, 2020 and~~ 2019, ~~were (7.0)% and (182.3)%, respectively. The decrease~~primarily due to a pre-tax loss in ~~the income tax benefit was primarily the result of higher~~2019 compared to pre-tax income in 2020 and a write-off of a deferred tax asset associated with PG&E Corporation stock contributed into a Fire Victim Trust. For more information on the ~~three months ended March 31, 2020, compared~~tax treatment of contributions to the ~~same period in 2019.~~Fire Victim Trust, see “Tax Matters” above.

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

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.

Upon 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 Proceeding 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.

As of the Effective Date, PG&E Corporation and the Utility had access to approximately $2.8 billion of total liquidity comprised of approximately $174 million of Utility cash, $343 million of PG&E Corporation cash and $2.3 billion of availability under the Utility and PG&E Corporation credit facilities. Due to the timing of payments made in accordance with the terms of the Plan, on July 1, 2020, the Utility borrowed $775 million on its revolving credit facility. The $775 million was repaid in full by July 17, 2020.

As a result of the outbreak of COVID-19, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could continue to be significantly affected. The Utility ~~is in the early stages of evaluating~~continues to evaluate the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist, including the moratorium on service disconnections and an observed reduction in non-residential electrical load. The reduction in cash collections from customers may be partially offset by reductions in discretionary capital spending or potential regulatory or payroll tax policy changes. As of March 31, 2020, PG&E Corporation and the Utility had access to approximately $4.6 billion of total liquidity comprised of approximately $1.5 billion of Utility cash, $0.4 billion of PG&E Corporation cash and $2.7 billion of availability under the DIP Credit Agreement.

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 and is pending CPUC approval. (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, PG&E Corporation and the Utility hold restricted cash that primarily consists of cash held in escrow pending the resolution of claims under the Plan.

~~Borrowings under~~In connection with the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 ~~Case. The Utility’s obligations under the DIP Facilities are guaranteed by~~Cases, PG&E Corporation and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case. The DIP Facilities will mature on December 31, 2020, subject to the ~~Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee. The~~ Utility ~~paid customary fees and expenses in connection with obtaining~~entered into the DIP ~~Facilities.~~Credit Agreement, which received final approval from the Bankruptcy Court on March 27, 2019.

On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and received the proceeds of such borrowing, net of original issue discount and repayment of the $350 million in outstanding borrowings under the DIP Revolving Facility. The DIP Initial Term Loan Facility matures on December 31, 2020 (subject to an extension option described further below) and bears interest at a spread of 225 basis points over LIBOR. On January 29, 2020, the Utility borrowed $500 million under the DIP Delayed Draw Term Loan Facility.

As of ~~April 29,~~June 30, 2020, the Utility had outstanding borrowings of $1.5 billion under the DIP Initial Term Loan Facility, $500 million under the DIP Delayed Draw Term Loan Facility, and ~~$815~~$904 million in face amount of letters of credit outstanding under the DIP Revolving Facility. As of ~~April 29,~~June 30, 2020, there were undrawn commitments of ~~$2.7~~$2.6 billion on the DIP Revolving Facility.

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~~There~~On July 23, 2020, PG&E Corporation sent a notice of 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 six months ended June 30, 2020, there were no issuances under ~~the PG&E Corporation February 2017 equity distribution agreement for the three months ended March 31, 2020.~~this agreement.

Beginning January 1, 2019, PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash.Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

In connection with its emergence from Chapter 11, in July 2020, PG&E Corporation ~~expects~~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 ~~issue new~~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, representing the right to receive, on maturity, between 125 million and 153 million shares of PG&E Corporation common ~~stock for up~~stock. Such gross proceeds were used to ~~$9.0 billion of proceeds at or prior to emergence from Chapter 11 in order to finance~~fund distributions under the Plan. ~~The structure, terms and conditions of any such equity issuance are expected~~For more information, see Note 6 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. There can be no assurance that any such equity offering would be successful. PG&E Corporation has obtained the Backstop Commitment Letters providing for equity funding of up to $12.0 billion to finance the transactions contemplated by the Plan. In the event that new equity offerings do not raise at least $9.0 billion of proceeds, or if additional capital is required, PG&E Corporation may draw on the Backstop Commitments for equity funding of up to $12.0 billion, subject to satisfaction or waiver by the Backstop Parties of the conditions set forth therein. (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” in Note 2 of 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 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 in accordance with the terms and conditions contained in the Plan.

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

On the Effective Date, pursuant to the Plan, the Utility reinstated $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 ~~expect that~~Reinstated Senior Notes are secured by a first lien, subject to permitted liens, on substantially all of the ~~funding for~~Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the ~~Plan will consist of both new debt and equity for both PG&E Corporation~~New Mortgage Bonds and the Utility ~~as well as~~Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other ~~sources~~existing or future first mortgage bonds issued under the Utility’s mortgage indenture.

On the Effective Date, by operation of ~~funding totaling approximately $58 billion. For additional information, see~~ the ~~2019 Form 10-K.~~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 ~~April 30,~~July 1, 2020, the Utility ~~filed~~obtained a $1.5 billion 364-day and a $1.5 billion 18-month secured term loan under a term loan credit agreement. For more information, see “Credit Facilities” discussion below.

For more information, see “Long-Term Debt” in Note 5 to the Notes to the Condensed Consolidated Financial Statements in Item 1.

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 ~~CPUC seeking authorization for a post-emergence securitization transaction. (For~~net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan.

For more information, ~~regarding~~see “Long-Term Debt” in Note 5 to the ~~application,~~Notes to the Condensed Consolidated Financial Statements in Item 1.

On May 26, 2020, the Utility entered into (i) the Utility RCF Commitment Letter, pursuant to which the Utility RCF Commitment Parties agreed, subject to the terms and satisfaction or waiver of the conditions contained therein, to provide a $3.5 billion revolving credit facility (the “Utility Revolving Credit Facility”) to the Utility and (ii) the Utility Term Loan Commitment Letter, pursuant to which the Utility Term Loan Commitment Parties agreed, subject to the terms and satisfaction or waiver of the conditions contained therein, to provide an up to $3 billion term loan credit facility (the “Utility Term Loan Credit Facility,” as amended on June 19, 2020) to the Utility.

The Utility Revolving Credit Facility has tenor of three years, subject to two one-year extension options. The proceeds from the Utility Revolving Credit Facility were used in part to fund transactions contemplated under the Plan and are intended to finance working capital needs, capital expenditures and other general corporate purposes of the Utility and its subsidiaries. The Utility Term Loan Credit Facility is comprised of two tranches, with tenors of 364 days and 18 months. The proceeds from the Utility Term Loan Credit Facility were used to fund transactions contemplated under the Plan.

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM, and Citibank, N.A. as co-administrative agents and Citibank, N.A., as the designated agent as contemplated by the Utility RCF Commitment Letter. The Utility Revolving Credit Agreement has a maturity date three years after its Effective Date, subject to two one-year extensions at the option of the Utility.

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 Agreement”) with JPM, as administrative agent, the other lenders from time to time party thereto as contemplated by the Utility Term Loan Commitment Letter. 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 364-Day Term Loan Facility is 364 days after the Effective Date of the Utility Term Loan Credit Agreement and the maturity date for the 18-Month Term Loan Facility is eighteen months after the Effective Date of the Utility Term Loan Credit Agreement.

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

On May 26, 2020, PG&E Corporation entered into a commitment letter (the “Corporation RCF Commitment Letter”) with respect to a $500 million revolving credit facility (the “Corporation Revolving Credit Facility”), which was executed on July 1, 2020.

The Corporation Revolving Credit Facility matures in three years, subject to two one-year extension options. 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 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, and the lenders from time to time party thereto as contemplated by the Corporation RCF Commitment Letter. 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.

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 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 at most 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.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant. Certain debt instruments contain covenants that restrict the ability of the Utility to pay dividends to PG&E Corporation. PG&E Corporation and the Utility do not expect to commence payment of dividends on its common or preferred stock upon emergence from Chapter 11.

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

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~~six months ended ~~March 31,~~June 30, 2020, net cash provided by operating activities ~~decreased~~increased by ~~$662~~$24 million compared to the same period in 2019. This ~~decrease~~increase was primarily due to ~~an increase~~a $19 million decrease in ~~vendor payments in 2020 that were not~~interest paid during the ~~first quarter of 2019 due~~six months ended June 30, 2020, as compared to the ~~automatic stay as of the Petition Date, and a reduction~~same period in ~~cash receipts from customers as a result of the economic impacts of the COVID-19 pandemic.~~2019.

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

The Utility had material obligations outstanding as of the Petition Date, including claims related to the 2018 Camp fire and 2017 Northern California wildfires. Any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Future operating cash flows will be materially impacted by the timing of certain transactions and ~~outcome~~the satisfaction of claims against and interests in the Utility, in accordance with the terms of the ~~Chapter 11 Cases.~~Plan.

Net cash used in investing activities increased by ~~$408~~$1,007 million during the ~~three~~six months ended ~~March 31,~~June 30, 2020 as compared to the same period in 2019. 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.

Net cash provided by financing activities increased by ~~$245 million~~$7.9 billion during the ~~three~~six months ended ~~March 31,~~June 30, 2020 as compared to the same period in 2019. This increase was primarily due to ~~an additional $150 million~~the Utility’s ability to obtain $8.925 billion in first mortgage bonds as a result of the confirmation of the Plan. Additionally, the Utility reduced its net borrowings under the DIP ~~Facilities and an approximately $90 million reduction in amounts paid for DIP credit facility debt issuance costs in~~facilities by $1.0 billion during the six months ended June 30, 2020, as compared to ~~2019. Additionally,~~ the ~~Utility paid $30 million in bridge facility financing fees in 2020, with no similar amount~~same period in 2019.

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 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. 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.

99

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

The order noted that the court will be flexible in approving any protocols submitted by May 28, 2020, that achieve the essence of the newly imposed conditions of probation if the CPUC, the federal monitor, and the Utility unanimously recommend such protocols. ~~While the Utility is in the early stages of analyzing the proposed probation conditions, such~~Such conditions, if implemented, could have a material effect on the Utility’s financial condition, results of operations, liquidity and cash flows.

On May 13, 2020, the Utility filed motions with the court asking that it reconsider the order and issue a stay on implementing the new conditions until it has had a chance to rule on the Utility’s request for reconsideration.

Also, on May 13, 2020, the Utility filed a notice of appeal with the Ninth Circuit Court of Appeals.

On May 14, 2020, the court issued an order staying the April 29th order and ordering certain other procedural actions. On June 24, 2020, after a hearing on the Utility’s motion for reconsideration, the Utility filed a joint brief with the Monitor overseeing its probation and the Department of Justice, outlining which actions, if any, the court should take regarding the conditions of the Utility’s probation. On July 1, 2020, the court issued a notice inviting comments from “any interested party . . . on whether and the extent to which these joint proposed probation conditions should be accepted.” One interested party filed comments on July 16, 2020, stating that the proposed probation conditions submitted by the joint parties were inadequate and should be rejected by the court. The CPUC also filed comments indicating it did not oppose the conditions agreed to by the Utility, the Monitor, and the Department of Justice.

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 report to the court to update the court on the condition of the Utility’s 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.

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

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

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

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

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.

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

The CPUC’s capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio by 1% or more. The CPUC’s decisions state that the Utility shall not be considered in violation of these conditions during the period the waiver application is pending resolution. Due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019. ~~The waiver is subject to CPUC approval.~~

On February 27, 2020, the Utility filed a pleading to notify the CPUC of an additional decline in its equity ratio to approximately 20.4%, based on information reported in its 2019 Form 10-K, primarily related to non-cash charges related to the 2018 Camp fire and the 2017 Northern California wildfires.

A Proposed Decision was issued on April 1, 2020. IfThe CPUC approved the ~~Proposed Decision would grant the Utility’s request for a waiver. A final decision is expected to be voted out~~PD on May 7, 2020. The PD granted the Utility a temporary waiver of the capital structure requirement until such time as the CPUC finds it appropriate in the Chapter 11 Proceedings OII. As disclosed in Other Regulatory Proceedings, the CPUC’s decision in the Chapter 11 Proceedings OII 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.

For additional information, see 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 Chapter 11 Proceedings OII ~~to 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 from 5.16%, as currently authorized, to 4.17% to implement the interest cost savings resulting from the Utility’s exit financing. If approved, the Utility’s authorized cost of long-term debt will be in effect beginning 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, 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, the CPUC’s Office of the Safety Advocate, the National Diversity Coalition, the Center for Accessible Technology, the Small Business Utility Advocates, and California City County Street Light Association filed a motion with the CPUC seeking approval of a settlement agreement that resolves all of the issues raised by these parties in the Utility’s 2020 GRC.

As a result of the settlement agreement and based on other facts and circumstances known to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility expect to remain on track to satisfy the rate base conditions included in their exit financing documents.

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

On June 30, 2020, the Utility filed the 2020 Risk Assessment Mitigation Phase Report (“RAMP”).

PG&E Corporation and the Utility expect a decision in the second half of 2020.

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 in the future if the CPUC’s audit of 2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process. The Utility cannot predict the timing and outcomeseparate application upon completion of the audit.

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 twelve 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 October 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. 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 the FERC issues its decision, the Utility expects one or more parties to seek rehearing of that decision and then appeal it to the courts. 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; and requires the Utility to seek FERC authorization before recovering claims related to 2017 and 2018 fires. The remaining, unresolved issues, including regarding the Utility’s return on equity, capital structure, depreciation rates, as well as certain questions regarding the Utility’s formula rate, have been set for hearing at FERC. The parties recently submitted and the Chief ALJ granted a request that the hearing schedule be held in abeyance until October 1, 2020 pending further settlement discussions. The Utility is unable to predict the timing and outcome of this proceeding.

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. FERC has not yet acted on this second filing.

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 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.~~

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

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 catastrophic events that included twelve 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 and a scoping memo was issued on December 6, 2019. On March 10, 2020, the Utility filed a Motion for Interim Rate Relief, requesting $135.4 million of interim rates to be recovered starting August 2020. On April 7, 2020, the ALJ granted the Utility’s request to withdraw the motion without prejudice. The Utility may refile it should the 2019 CEMA schedule be delayed.

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 settlement. The ALJ has suspended evidentiary hearings and set a status conference for July 30, 2020. 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.

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.

~~For the~~The amount ~~recorded to~~reflected in this memorandum account as of ~~March 31,~~June 30, 2020 was $261 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.

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 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 and authorization in a separate proceeding or through a GRC. 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,~~June 30, 2020 was $98 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, as required by Public Utilities Code Sections 8386 et 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, 2020, as of the ~~effective date,~~Effective Date, June 5, 2019.

Also, as previously disclosed, 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 anticipates that the recovery of the costs recorded to the WMPMA would occur through a general rate case or future application at which time the CPUC would review the costs for reasonableness as required by AB 1054. 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 recorded in the WMPMA, which the Utility expects will be substantial.

~~For the~~The amount ~~recorded to~~reflected in this memorandum account as of ~~March 31,~~June 30, 2020 was $993 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.

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

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, the Utility submitted an updated advice letter to modify and clarify prior proposals based on CPUC guidance.

The CPUC has not yet approved the Utility’s advice letter, therefore, as of June 30, 2020, $35 million in CPPMA costs for the period between March 4, 2020 and June 30, 2020 were recorded in noncurrent Regulatory assets on the Condensed Consolidated Balance Sheets.

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 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 financial status by August 7, 2020. The Utility expects that its updated testimony will reflect, among other things, PG&E Corporation’s and Utility’s exit financings from Chapter 11 and related equity issuances, including to the Fire Victim Trust, in connection with consummating the Plan on July 1, 2020, issuance of revised credit ratings, updated financial forecasts for the Utility and their impacts on the securitization application, including on the Stress Test Costs and the Customer Credit Trust, as well as certain expected tax impacts.

The foregoing description of anticipated 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 cash on hand, accrued interest, trade payables and other amounts). This description reflects PG&E Corporation’s and the Utility’s expectations as of the date of this filing and remains subject to change. (See “Forward-Looking Statements” above).

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”) with the CPUC, and amended it subsequently on February 12, February 14, and 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 and utility survey. The Utility’s 2020 Wildfire Mitigation Plan 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 are due on September 9, 2020 and the third, Conditions C are due as part of the 2021 WMP update in February 2021. The Utility ~~expect~~is working to provide all updates and information to meet the ~~CPUC to issue a decision on its 2020-2022 WMP by June 2020.~~ Conditions.

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, and the 2020-2022 Wildfire Mitigation Plan 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. Participants in the solicitation for the permanent generation have been notified of the solicitation’s termination. 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 following reasonableness review. 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 ~~proceeding~~application or ~~through~~ a ~~GRC.~~general rate case.

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).

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to 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 the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date.

For additional information, see 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.

~~Comments on the ALJ’s proposed decision are due May 11, 2020 and reply comments are due May 18, 2020. A final decision is expected in May 2020.~~

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 (“Regional Plan 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.

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

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 to support the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision finding that the imposition of the non-bypassable charge 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.

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 during the first half of 2020, which will continue throughout the second half of 2020. Approval of the framework is expected by the end of 2020.

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). In accordance with the procedural schedule for ~~July~~Phase I, the CPUC staff is expected to issue its Report in September 2020. Parties may then submit opening and reply comments 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 CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed utilities 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 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 July 6th, 2020, the CPUC issued a proposed decision on Topic 4 and Topic 5 for disadvantaged communities and Climate Vulnerability Assessments (“CVA”). In the proposed decision, the CPUC instructed IOUs to create “climate change teams” across departments, with cross-departmental responsibilities who will report directly to an executive at the SVP level or above. Continuing, the IOUs shall report on organizational structure and provide individual names and department titles. Board members should take responsibility for climate adaptation planning, as informed by senior leadership. The ~~remaining topics~~scope of CVAs are proposed to consider climate risks to assets, operations, and services over which IOUs have direct control, as well as third party power providers, and consider promoting equity in ~~phase one~~Disadvantaged Vulnerable Communities. CVAs are proposed to coincide with each IOUs GRC cycle, and a new chapter on Climate Adaptation is required in future GRCs. A significant program of ~~this proceeding are still under consideration~~community outreach and ~~will~~engagement on climate adaptation must also be undertaken by the IOUs, subject to a ~~separate decision. Those issues include: guidance~~Community Engagement Plan that they must submit within 90 days of the CPUC’s Final Decision in this , and a new chapter on ~~how~~Climate Adaptation is required in future GRCs. A significant program of community outreach and engagement on climate adaptation ~~should~~must also be ~~incorporated into~~undertaken by the ~~investor-owned utilities’ investment plans, program design, and operations and how climate change might affect vulnerable and disadvantaged communities. The CPUC decision~~IOUs, subject to a Community Engagement Plan that they must submit within 90 days of the CPUC’s Final Decision in this OIR. A new memorandum account, the Climate Adaptation Vulnerability Assessment Memorandum Account – CAVAMA, is proposed to cover CVA costs. Opening comments were filed on ~~such issues is anticipated no earlier than mid-2020.~~July 27th.

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 Utility and other entities (including 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 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 motion.~~the Joint Motion.

On June 15, 2020, fourteen parties (including telecommunications providers, CCAs, and 10 cities and counties) filed a joint motion requesting that the CPUC perform a reasonableness review of past IOU PSPS events to determine whether each was reasonable. PG&E Corporation and the Utility are unable to predict the timing and the outcome of this request.

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

On November 12, 2019, the assigned commissioner and ALJ in the OIR to Examine 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 and October 23-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, the ALJ held a status conference at which parties discussed those issues. The ALJ indicated that a further ruling, setting forth a schedule for the remainder of the proceeding, would be forthcoming.

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 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. The ALJ indicated that a ruling on those issues would be forthcoming.

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

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.

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On June 30, 2020, the CPUC issued a PD that would provide a non-Utility provider an option to prepay their entire PCIA obligation. The earliest date the CPUC will consider this prepayment option is August 6, 2020.

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 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”~~“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 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 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund, subject to the conditions set forth in AB 1054. 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.

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~~six months ended ~~March 31,~~June 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. PG&E Corporation and the Utility will 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. At June 30, 2020, PG&E Corporation and the Utility satisfied the eligibility and other requirements set forth in AB 1054 and as a result, upon payment of the initial contribution on the Effective Date, the Wildfire Fund is available to pay for eligible claims arising as of the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising as of the effective date of AB 1054 and the Utility’s emergence from Chapter 11, 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. Therefore, PG&E Corporation and the Utility have 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 are non-current, called “Wildfire fund asset” in the Condensed Consolidated Balance Sheets. On June 30, 2020, the Utility recorded amortization expense of $173 million related to the coverage received from the effective date of AB 1054 to June 30, 2020. 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. 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 used a Monte Carlo simulation based on twelve years of historical data from wildfires caused by electrical equipment to estimate expected loss. The assumptions create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The most significant assumption is the 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. PG&E Corporation and the Utility utilize historical, publicly available fire-loss data as a starting point; however, future fire-loss can be difficult to estimate due to uncertainties around the impacts of climate change, land use changes, and mitigation efforts by the California electric utility companies.

Other assumptions 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 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 will 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. 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 June 30, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset.

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,~~June 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,~~June 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.

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

The order noted that the court will be flexible in approving any protocols submitted by May 28, 2020, that achieve the essence of the newly imposed conditions of probation if the CPUC, the federal monitor, and the Utility unanimously recommend such protocols. ~~While the Utility is in the early stages of analyzing the proposed probation conditions, such~~Such conditions, if implemented, could have a material effect on the Utility’s financial condition, results of operations, liquidity and cash flows.

On May 13, 2020, the Utility filed motions with the court asking that it reconsider the order and issue a stay on implementing the new conditions until it has had a chance to rule on the Utility’s request for reconsideration.

Also, on May 13, 2020, the Utility filed a notice of appeal with the Ninth Circuit Court of Appeals.

On May 14, 2020, the court issued an order staying the April 29th order and ordering certain other procedural actions. On June 24, 2020, after a hearing on the Utility’s motion for reconsideration, the Utility filed a joint brief with the Monitor overseeing its probation and the Department of Justice, outlining which actions, if any, the court should take regarding the conditions of the Utility’s probation. On July 1, 2020, the court issued a notice inviting comments from “any interested party . . . on whether and the extent to which these joint proposed probation conditions should be accepted.” One interested party filed comments on July 16, 2020, stating that the proposed probation conditions submitted by the joint parties were inadequate and should be rejected by the court. The CPUC also filed comments indicating it did not oppose the conditions agreed to by the Utility, the Monitor, and the Department of Justice.

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 report to the court to update the court on the condition of the Utility’s 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.

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

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

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

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

On June 2, 2020, the ALJ sent a procedural email disclosing a forthcoming ruling requesting input from parties on the scope, schedule and priorities for the Safety Culture OII, and indicating that after such pleadings are filed a new scoping memorandum would be issued.

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

For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board, the Utility, and the California Attorney General’s Office, see Part I, Item 3. “Legal Proceedings” in the 2019 Form 10-K.

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see the section of the 2019 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Forward-Looking Statements.”

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire.

On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. Cal Fire stated that it had “determined that the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is reviewing the matter.

Although there are a number of unknown facts surrounding Cal Fire’s causation determination, the Utility could be subject to significant liability in excess of insurance coverage that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation and the Utility have also received and are responding to data requests from the CPUC’s SED relating to the Kincade fire. PG&E Corporation and the Utility could be the subject of additional investigations, lawsuits, or enforcement actions in connection with the 2019 Kincade fire.

In addition, the 2019 Kincade fire or future wildfires could have adverse consequences on the Utility’s probation proceeding, the Utility’s proceedings with the CPUC and FERC (including the Safety Culture OII), and future regulatory proceedings, including future applications for the safety certification required by AB 1054. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment. For more information about the 2019 Kincade fire, see Note 10 “Wildfire-Related Contingencies” in Part I, Item 1.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been (beginning in March 2020) and ~~will~~could continue to be significantly affected by the outbreak of ~~COVID-19.~~COVID-19, but the extent of such impact is uncertain. In December 2019, a novel strain of coronavirus (COVID-19) was reported to have surfaced in Wuhan, China, resulting in significant disruptions to manufacturing, supply chain, markets, and travel world-wide. On January 30, 2020, the International Health Regulations Emergency Committee of the World Health Organization declared the COVID-19 outbreak a public health emergency of international concern and on March 12, 2020, announced the outbreak was a pandemic. On March 19, 2020, the California Governor instituted shelter-in-place measures that became effective state-wide on March 19, 2020. It is currently uncertain when and how the shelter-in-place measures will be lifted. On March 16, 2020, the Governor issued an Executive Order requiring the CPUC ~~directed~~to direct electric utility companies to follow customer protection measures including a moratorium on service disconnections, retroactive to March 4, 2020. On March 19, 2020, the California Governor instituted shelter-in-place measures that became effective state-wide on March 19, 2020. On April 28, 2020, the California Governor announced four different stages for easing the California shelter-in-place measures. On May 4, 2020, the California Governor issued an executive order directing the State Public Health Officer to establish criteria to determine whether and how local health officers may implement less restrictive measures, and on May 7, 2020, the State Public Health Officer issued an order, effective May 8, 2020, directing local health officers to begin gradual movement into Stage 2 of the Pandemic Resilience Roadmap for the State of California in which the shelter-in-place measures are modified to allow certain low-risk businesses and other spaces to re-open. However, the previously announced stages of reopening are subject to modifications as California’s COVID-19 data evolves. On July 13, 2020, the California Department of Public Health issued an order, effective immediately, indicating community spread of infection is of increasing concern across the state and directing closures of certain indoor and/or outdoor spaces and businesses, unless an exception applies. It is uncertain when further modifications and restrictions will be implemented.

While the extent of the impact of the current COVID-19 ~~coronavirus~~ outbreak on PG&E Corporation and the Utility’s business and financial results is uncertain, the consequences of a continued and prolonged outbreak and resulting ~~protective~~ government and regulatory orders could have a further negative impact on the Utility’s financial condition, results of operations, liquidity and cash flows.

The outbreak of COVID-19 and the resulting economic conditions, including but not limited to the shelter-in-place order and resulting decrease in economic and industrial activity in the Utility’s service territory ~~which has not been entirely offset by an increase in daytime household electrical use,~~ have and will continue to have a significant adverse impact on the Utility’s ~~customers and, as a result,~~customers; these circumstances ~~impact~~have impacted and will continue to impact the Utility for a period of time that PG&E Corporation and the Utility are unable to predict. For example, the economic downturn has already resulted in a reduction in customer receipts and collection delays ~~for March and April~~in the second quarter of 2020.

AsThe Utility’s customer energy accounts receivable balances over 30 days outstanding as of June 30, 2020 were approximately $491 million, or $148 million higher as compared to the corresponding month in 2019. The Utility is unable to estimate the portion of the ~~time~~increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections in 2020 and for as long as current COVID-19 circumstances persist.

In addition, the Utility has ~~also~~ experienced average reductions of approximately 3% in electric load and approximately 4% in core gas load on a ~~net decrease~~weather-adjusted basis from mid-March to mid-July, resulting in ~~total non-residential electrical load, leading to a~~an estimated $200 million reduction in billed revenues ~~from non-residential customers.~~for the mid-March to mid-July period. PG&E Corporation and the Utility are currently unable to quantify the long-term potential impact of the changes in customer collections or changes in energy demand on earnings and cash ~~flows.~~

Although the Utility continues to prioritize customer and community safety, these disruptions necessitate changes to the Utility’s operating and capital expenditure plans, which could lead to project delays or service disruptions ~~and otherwise adversely impact operations and planning.~~in certain programs. Delays in production and shipping of materials used in the Utility’s operations may also ~~adversely~~ impact operations.

In addition, COVID-19 has the potential to cause delays and disruptions in various regulatory proceedings in which the Utility is involved. Following Department of Health guidance concerning restrictions on public gatherings, the CPUC has cancelled all public forums and has been conducting remote meetings for events it deems essential. A disruption in CPUC operations could impact the timing of PG&E Corporation’s and the Utility’s rate cases and other regulatory proceedings.

In addition, as discussed above, a group of local government entities and organizations filed a Joint Motion asking the CPUC to require utilities to comply with additional requirements when implementing PSPS events while local areas are sheltering-in-place due to COVID-19. A CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. Potential ~~longer term~~longer-term impacts of COVID-19 on PG&E Corporation or the Utility include the potential for higher credit spreads and borrowing costs ~~due to the increasing difference in the higher yield of lower-rated debt as compared to the lower yield of higher-rated debt of similar maturity~~ and incremental financing needs. PG&E Corporation and the Utility’s analysis of the potential impact of COVID-19 is preliminary and subject to change. PG&E Corporation and the Utility are unable to predict the timing, duration or intensity of the COVID-19 situation and its effects on the business and general economic conditions in the State of California and the United States of America.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.

For more information on AB 1054, see “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

~~The outbreak of COVID-19~~PG&E Corporation and the ~~resulting economic downturn~~Utility have ~~adversely affected~~a substantial amount of indebtedness as a result of the ~~financial markets~~reorganization transactions in connection with implementation of the Plan, most of which is secured by liens on the assets of PG&E Corporation and the ~~economy more generally and could result in an economic downturn.~~Utility. As of ~~March 31,~~June 30, 2020, on an as adjusted basis after giving effect to such reorganization transactions (including the ~~S&P 500~~amounts of indebtedness that PG&E Corporation and the Utility incurred on the Effective Date) as if such transactions occurred on June 30, 2020, PG&E Corporation would have had ~~declined over 20%~~approximately $4.75 billion of outstanding indebtedness (such indebtedness consisting of the 2028 Notes, the 2030 Notes and borrowings under the Term Loan), and the Utility would have had approximately $33.3 billion of outstanding indebtedness (such indebtedness including the Utility Reinstated Senior Notes, the Mortgage Bonds and the Utility Term Loan Credit Agreement). In addition, PG&E Corporation and the Utility would have had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility would have had $2.53 billion of additional borrowing capacity under the Utility Revolving Credit Agreement (after taking into account letters of credit outstanding under the DIP revolving facility that will become outstanding under the Utility Revolving Credit Agreement on the Effective Date, which, as of June 30, 2020, were $904 million). In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million.

Since PG&E Corporation and the Utility will have a historically high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt. Furthermore, since a significant percentage of the Utility’s assets are used to secure its ~~previous~~debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets. This relatively high ~~close recorded~~level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including:

Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are ~~relying~~permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks. As a result of the high level of indebtedness, PG&E Corporation and the Utility may be unable to generate sufficient cash through operations to service such debt, and may need to refinance such indebtedness at or prior to maturity and be unable to obtain financing on ~~the equity and debt capital markets in order to finance their emergence from Chapter 11. Although PG&E Corporation’s expected equity raise for approximately $9 billion~~suitable terms or at all, any of net cash proceeds is backstopped by the Backstop Commitment Letters, obtaining financing from the capital markets at higher price-to-earnings multiples than the multiple contemplated by the Backstop Commitment Letters would result in significantly less dilution to shareholders. In addition, it is possible that the commitments under the Backstop Commitment Letters are not available due to potential termination events orwhich could have a ~~default by one or more backstop parties. With respect to the debt financing,~~material adverse effect on PG&E Corporation’s and the Utility’s business, financial condition and results of operations.

PG&E Corporation’s and the Utility’s material financing agreements, including certain of their respective credit agreements and indentures, contain various covenants restricting, among other things, their ability to:

The restrictions contained in these material financing agreements could affect PG&E Corporation’s and the Utility’s ability to operate their business and may limit their ability to react to market conditions or take advantage of potential business opportunities as they arise. For example, such restrictions could adversely affect PG&E Corporation’s and the Utility’s ability to finance their operations and expenditures, make strategic acquisitions, investments or alliances, restructure their organization or finance their capital needs. Additionally, PG&E Corporation’s and the Utility’s ability to comply with these covenants and restrictions may be affected by events beyond their control, including, but not limited to, prevailing economic, financial and industry conditions.

Following entry of the Confirmation Order confirming the Plan, certain parties filed notices of appeal with respect to the Confirmation Order. There can be no assurance that any such appeal will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility.

On the Effective Date, PG&E Corporation issued to the Fire Victim Trust a number of shares of common stock equal to 22.19% of the outstanding common stock on such date. As further described in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1, PG&E Corporation may be required to issue shares of its common stock in respect of allowed HoldCo Rescission or Damage Claims. If such issuance is required, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of PG&E Corporation common stock such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Effective Date, assuming that such issuance of shares in respect of the HoldCo Rescission or Damage Claims had occurred on the Effective Date. Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline.

PG&E Corporation has incurred and will incur in connection with the Plan significant net operating loss carryforwards and other tax attributes, the amount and availability of which are ~~supported~~subject to certain qualifications, limitations and uncertainties. The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the “capital stock”) and other interests designated as “stock” of PG&E Corporation by ~~$11.9~~the Board of Directors as disclosed in an SEC filing (such stock and other interests, the “Equity Securities,” and such restrictions on transferability and ownership, the “Ownership Restrictions”) in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation’s ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for federal income tax purposes. Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid.

Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities. Any transferee receiving Equity Securities that would result in a violation of the Ownership Restrictions will not be recognized as a shareholder of PG&E Corporation or entitled to any rights of shareholders, including, without limitation, the right to vote and to receive dividends or distributions, whether liquidating or otherwise, in each case, with respect to the Equity Securities causing the violation.

The Ownership Restrictions remain in effect until the earliest of (i) the repeal, amendment or modification of Section 382 (and any comparable successor provision) of the Internal Revenue Code, in a manner that renders the restrictions imposed by Section 382 of the Internal Revenue Code no longer applicable to PG&E Corporation, (ii) the beginning of a taxable year in which the Board of Directors determines that no tax benefits attributable to net operating losses or other tax attributes are available, (iii) the date selected by the Board of Directors if it determines that the limitation amount imposed by Section 382 of the Internal Revenue Code as of such date in the event of an “ownership change” of PG&E Corporation (as defined in Section 382 of the Internal Revenue Code and Treasury Regulation Sections 1.1502-91 et seq.) would not be materially less than the net operating loss carryforwards or “net unrealized built-in loss” (within the meaning of Section 382 of the Internal Revenue Code and Treasury Regulation Sections 1.1502-91 et seq.) of PG&E Corporation and (iv) the date selected by the Board of Directors if it determines that it is in the best interests of PG&E Corporation’s shareholders for the Ownership Restrictions to be removed or released. The Ownership Restrictions may also be waived by the Board of Directors on a case by case basis.

The Plan contemplates that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, subject to PG&E Corporation’s ability to elect to treat the Fire Victim Trust as a “grantor trust” for U.S. federal income tax purposes instead. Based on the facts known to date, PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a “grantor trust”, but only if PG&E Corporation receives favorable determinations from the Internal Revenue Service regarding certain aspects of such election. If PG&E Corporation does not receive such favorable determinations, it expects to treat the Fire Victim Trust as a “qualified settlement fund” for U.S. federal income tax purposes.

If PG&E Corporation were to elect to treat the Fire Victim Trust as a “grantor trust”, any shares owned by the Fire Victim Trust would effectively be excluded from the total number of outstanding Equity Securities when calculating a Person’s Percentage Ownership (as defined in the Amended Articles) for purposes of the Ownership Restrictions. For example, whereas the number of outstanding shares of PG&E Corporation common stock for corporate purposes as of July 27, 2020, was 1,941,473,377 shares, for purposes of the Ownership Restrictions, the number of outstanding common stock as of July 27, 2020, would be the number of outstanding shares of PG&E Corporation common stock less the number of shares of common stock owned by the Fire Victim Trust, or total outstanding shares per SEC less 476,995,175. Note that PG&E Corporation does not control the number of shares held by the Fire Victim Trust and is not able to determine in advance the number of shares the Fire Victim Trust will hold at any time. PG&E Corporation intends to periodically make available to investors information about the number of shares of common stock held by the Fire Victim Trust as of a specified date for purposes of the Ownership Restrictions, including in its Quarterly Reports and Annual Reports filed with the SEC.

PG&E Corporation will publicly announce its determination on whether it will elect to treat the Fire Victim Trust as a “grantor trust” no later than April 1, 2021. In the event PG&E Corporation decides to make a “grantor trust” election with respect to the Fire Victim Trust, PG&E Corporation intends to enforce the Ownership Restrictions as described in the foregoing paragraph (excluding any shares owned by the Fire Victim Trust from the number of outstanding Equity Securities), including with respect to Transfers (as defined in the Amended Articles) occurring before such announcement. However, it is anticipated that the Board of PG&E Corporation will exempt Transfers to shareholders occurring prior to the date hereof solely to the extent that such Transfers would have complied with the Ownership Restrictions if the Ownership Restrictions were applied on the basis that the shares owned by the Fire Victim Trust were treated as outstanding Equity Securities. For the avoidance of doubt, all other Transfers of Equity Securities (including acquisitions from and after the date hereof by shareholders benefitting from an exemption described in the preceding sentence) will continue to be subject to the Ownership Restrictions. All current and prospective shareholders are advised to consider the foregoing in determining their ownership and acquisition of PG&E Corporation common stock.

As of December 31, 2019, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $5.9 billion and $1.9 billion, respectively, and PG&E Corporation incurred and will incur in connection with the Plan significant net operating loss carryforwards and other tax attributes. The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations. Under Section 382 of the Internal Revenue Code (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an “ownership change,” and the corporation does not qualify for (or elects out of) the special bankruptcy exception in Section 382(l)(5) of the Internal Revenue Code, such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally 5% shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). Losses incurred in the same taxable year as an ownership change generally can be pro-rated between the pre- and post-change portions of the taxable year, even if a disproportionate amount of such losses were actually incurred on or prior to the date of the ownership change. Only the portion of such losses allocated to the pre-change portion of the year would be subject to the annual limitation.

As of the Effective Date, PG&E Corporation does not believe that it has undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code. However, whether PG&E Corporation underwent or will undergo an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred and will occur pursuant to the Plan depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects. Accordingly, there can be no assurance that the IRS would not successfully assert that PG&E Corporation has undergone or will undergo an ownership change pursuant to the Plan. In addition, even if these transactions did not cause an ownership change, they may increase the likelihood that PG&E Corporation may undergo an ownership change in the future. If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the Internal Revenue Code could be material to its operations.

In particular, limitations imposed on PG&E Corporation’s ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes. Specifically, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to a successful rate-neutral securitization transaction after the Effective Date, the proceeds of which are expected to be used to satisfy PG&E Corporation’s and the Utility’s obligations to the Fire Victim Trust, and to PG&E Corporation’s and the Utility’s commitment to make certain operating and capital expenditures. Failure to consummate a securitization transaction or obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation common stock.

In response to concerns raised by California Governor Gavin Newsom, PG&E Corporation and the Utility filed the Case Resolution Contingency Process Motion with the Bankruptcy Court setting forth certain commitments in connection with the confirmation process and implementation of the Plan, including, among other things, limitations on the ability of PG&E Corporation to pay dividends on shares of its common stock (the “Dividend Restriction”). The Dividend Restriction provides that PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Effective Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items. Additionally, the ruling of the court overseeing the Utility’s probation dated April 3, 2019 places further restrictions on the ability of PG&E Corporation and the Utility to issue dividends. Under the ruling, no dividends may be issued until the Utility is fully in compliance with all applicable laws concerning vegetation management and clearance requirements, as well as the vegetation management and enhanced vegetation management targets and metrics in the Utility’s wildfire mitigation plan.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, PG&E Corporation’s results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant. Certain of the Utility’s debt instruments contain covenants that restrict the ability of the Utility to pay dividends to PG&E Corporation.

PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility. Accordingly, PG&E Corporation’s cash flow and its ability to meet its debt service obligations under its existing and future indebtedness are largely dependent upon the earnings and cash flows of the Utility and the distribution or other payment of these earnings and cash flows to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances from the Utility. The ability of the Utility to pay dividends or make other advances, distributions and transfers of funds will depend on its results of operations and may be restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends, the conditions of the Utility’s probation proceeding and certain restrictive covenants contained in the agreements of those subsidiaries. The Utility is not expected to commence payment of dividends on its common stock or preferred stock upon emergence from Chapter 11. Additionally, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends and meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation. 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. In addition, the CPUC has imposed various conditions that govern the relationship between PG&E Corporation and the Utility, including financial conditions that require the Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. As a result of these restrictions and conditions, the Utility does not expect to commence payment of dividends on its common stock or preferred stock upon emergence from Chapter 11. The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to meet its obligations.

The Amended Articles and the Amended Bylaws contain provisions that may make the acquisition of PG&E Corporation more difficult without the approval of the Board of Directors, including, but not limited to, the following:

These and other provisions in the Amended Articles, the Amended Bylaws and California law could make it more difficult for shareholders or potential acquirers to obtain control of the Board of Directors or initiate actions that are opposed by the then-current Board of Directors, including delay or impede a merger, tender offer or proxy contest involving PG&E Corporation. The existence of these provisions could negatively affect the price of PG&E Corporation common stock and limit opportunities for shareholders to realize value in a corporate transaction.

The Utility’s financial results could be materially affected as a result of SB 901 adopted in 2018 by the California legislature. Pursuant to SB 901, 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 ~~bridge commitments. The remaining $6~~2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt ~~financing~~and accelerate a $700 million payment due to the Fire Victim Trust. Failure to consummate a securitization transaction could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. (See “Regulatory Matters - Other Regulatory Proceedings” in Item 7. MD&A.)

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC. SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan. Failure to substantially comply with the plan could result in fines and other penalties imposed on the Utility that could be material. (See “Regulatory Matters – Other Regulatory Proceedings” in Item 7. MD&A.)

On July 12, 2019, the California Governor signed into law AB 1054, which, among other policy reforms, provides for the establishment of a statewide fund that is 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. Although PG&E Corporation and the Utility have delivered notice to the CPUC electing to participate in the Wildfire Fund and even if the Utility were eligible to do so, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund are just and reasonable, subject to a disallowance cap, and that the Wildfire Fund has sufficient remaining funds.

The costs of participating in the Wildfire Fund (should the Utility be eligible to do so) are expected to exceed $6.7 billion over the anticipated ten-year life of the fund. The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.

Further, AB 1054 revised some of the SB 901 requirements regarding wildfire mitigation plans, including creating a Wildfire Safety Division to review future plans and that plans should cover a three-year period.

Also, in June 2018, the State of California enacted the CCPA, which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. On October 11, 2019, the State of California announced proposed regulations which provide guidance on the requirements of the CCPA. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. Failure to comply with the CCPA could result in fines imposed on PG&E Corporation and the Utility that could be material.

Finally, 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 is not supported by committed capital and will be subject to market conditions. PG&E Corporation and the Utility could also fail to satisfy the conditions in their existing Debt Commitment Letters (as defined above). In any event, adverse capital market conditions related to COVID-19 (or otherwise) could make it more difficult or expensive, or even infeasible, to emerge from Chapter 11 through the use of one or more capital market financing transactions.Reorganization.

~~During~~On the ~~quarter ended March 31, 2020,~~Effective Date, PG&E Corporation ~~did not make any~~made an equity ~~contributions~~contribution of $12.9 billion in cash, along with the Fire Victim Trust Shares, to the ~~Utility. Also during~~Utility, which used the ~~quarter ended March 31, 2020,~~funds to satisfy and discharge certain liabilities of PG&E Corporation ~~did not make any sales of unregistered~~and the Utility under the Plan and transferred the Fire Victim Trust Shares to the Fire Victim Trust. PG&E Corporation’s cash equity ~~securities in reliance on an exemption~~contribution was funded by proceeds from the financing transactions. This equity issuance to PG&E Corporation by the Utility was exempt from registration under the Securities Act of ~~1933,~~1933.

On June 7, 2020, PG&E Corporation entered into an Investment Agreement as ~~amended.~~described in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1. Pursuant to the terms of the Investment Agreement, on the Effective Date, PG&E Corporation issued 342.1 million shares of common stock to the Investors. This issuance and sale were exempt from registration under the Securities Act of 1933. The Investors represented to PG&E Corporation that they were “accredited investors” as defined in Rule 501 under the Securities Act and that the common stock was being acquired for investment purposes and not with a view to, or for sale in connection with, any distribution thereof, and acknowledged that the common stock acquired in connection with the Investment Agreement, or any transaction statement evidencing ownership of such common stock, would bear a restrictive legend.

On June 19, 2020, PG&E Corporation entered into the Forward Stock Purchase Agreements with the Backstop Parties as described in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The Forward Stock Purchase Agreement required PG&E Corporation to issue a number of shares of common stock equal to the unredeemed portion of such Backstop Party’s Greenshoe Backstop Purchase Amount divided by the Settlement Price (such shares of common stock, each Backstop Party’s “Greenshoe Backstop Shares”) to the Backstop Parties subject to the terms and conditions thereof. On August 3, 2020, PG&E Corporation will redeem $120.5 million of the Forward Stock Purchase Agreements as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement. On August 3 2020, PG&E Corporation will deliver 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 had not been redeemed. This issuance and sale will be exempt from registration under the Securities Act of 1933. The Backstop Parties represented to PG&E Corporation that they are “accredited investors” and that the Greenshoe Backstop Shares are being acquired for investment purposes and not with a view to, or for sale in connection with, any distribution thereof, and the Greenshoe Backstop Shares acquired in connection with the Forward Stock Purchase Agreements, or any transaction statement evidencing ownership of such shares, will bear an appropriate restrictive legend.

On the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust, pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477.0 million shares (such shares, the “Fire Victim Trust Shares”) of common stock of PG&E Corporation, no par value. The transfer of shares of common stock to the Fire Victim Trust was exempt from registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code, as approved by the Bankruptcy Court in the Order dated June 16, 2020.

On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash, along with the Fire Victim Trust Shares, to the Utility, which used the funds to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan and transferred the Fire Victim Trust Shares to the Fire Victim Trust as described above. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions described herein. This equity issuance to the Utility by PG&E Corporation was exempt from registration pursuant to Section 4(a)(2) of the Securities Act.

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 will deliver 748,415 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.

On August 3, 2020, PG&E Corporation will make an equity contribution of such additional 748,415 shares to the Utility, which will use the shares to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan (and related assignment agreement) and transfer the Fire Victim Trust Shares to the Fire Victim Trust as described above. This equity issuance to the Utility by PG&E Corporation will be exempt from registration pursuant to Section 4(a)(2) of the Securities Act.

During the quarter ended ~~March 31,~~June 30, 2020, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. PG&E Corporation does not have any preferred stock outstanding. During the quarter ended ~~March 31,~~June 30, 2020, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

As previously disclosed, the amended and restated bylaws of PG&E Corporation and the Utility provide that the next joint annual meeting of shareholders will take place within 15 months of the Effective Date on a date designated by the Boards of Directors. The Boards of Directors of PG&E Corporation and the Utility have not yet designated the date for such joint annual meeting. When the exact date has been determined, PG&E Corporation and the Utility intend to provide notice and the information required by Rule 14a-5(f) in a report filed with the SEC.

*~~This~~The Form of ~~Chapter 11 Plan Backstop Commitment Letter~~Consent Form is substantially ~~similar~~identical in all material respects to each ~~Chapter 11 Plan Backstop Commitment Letter~~Consent Form that is otherwise required to be filed as an exhibit, except as to the Backstop Party, ~~and~~ the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the ~~Chapter 11 Plan~~ Backstop Commitment Letter) and the amount of such Backstop Party’s Forward Contract Purchase Commitment (as defined in the Consent Form). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such ~~Chapter 11 Plan Backstop Commitment Letter,~~Consent Form, with a schedule dated as of June 9, 2020 identifying the ~~Chapter 11 Plan Backstop Commitment Letters~~Consent Forms omitted and setting forth the material details in which each ~~Chapter 11 Plan Backstop Commitment Letter~~Consent Form differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any ~~Chapter 11 Plan~~agreement so omitted.

**In accordance with Item 601(a)(5) of Regulation S-K, certain schedules (or similar attachments) to this exhibit have been omitted from this filing. Such omitted schedules (or similar attachments) include information relating to the Property. The registrants will provide a copy of any omitted schedule to the Securities and Exchange Commission or its staff upon request. In accordance with Item 601(b)(10)(iv) of Regulation S-K, certain provisions or terms of the Lease Agreement attached as an exhibit to the Agreement have been redacted. Such redacted information includes proprietary information about the Property. The registrants will provide an unredacted copy of the exhibit on a supplemental basis to the Securities and Exchange Commission or its staff upon request.

****Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

Dated: ~~May 1,~~July 30, 2020


GLOSSARY
FORWARD-LOOKING STATEMENTS
PART I. FINANCIAL INFORMATION
			ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
			PG&E CORPORATION
			CONDENSED CONSOLIDATED STATEMENTS OF INCOME
			CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
			CONDENSED CONSOLIDATED BALANCE SHEETS
			CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
			CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
			PACIFIC GAS AND ELECTRIC COMPANY
			CONDENSED CONSOLIDATED STATEMENTS OF INCOME
			CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
			CONDENSED CONSOLIDATED BALANCE SHEETS
			CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
			CONDENSED CONSOLIDATED STATEMENTS OF ~~SHAREHOLDER’S~~SHAREHOLDER S ’ EQUITY
			NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
			NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
			NOTE 2: BANKRUPTCY FILING
			NOTE 3: SIGNIFICANT ACCOUNTING POLICIES
			NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
			NOTE 5: DEBT
			NOTE 6: EQUITY
			NOTE 7: EARNINGS PER SHARE
			NOTE 8: DERIVATIVES
			NOTE 9: FAIR VALUE MEASUREMENTS
			NOTE 10: WILDFIRE-RELATED CONTINGENCIES
			NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
			NOTE 12: SUBSEQUENT EVENTS
			ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
			OVERVIEW
			RESULTS OF OPERATIONS
			LIQUIDITY AND FINANCIAL RESOURCES
			ENFORCEMENT AND LITIGATION MATTERS
			REGULATORY MATTERS
			LEGISLATIVE AND REGULATORY INITIATIVES
			ENVIRONMENTAL MATTERS
			CONTRACTUAL COMMITMENTS
			RISK MANAGEMENT ACTIVITIES
			CRITICAL ACCOUNTING POLICIES
			ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
			ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
			ITEM 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
			ITEM 1. LEGAL PROCEEDINGS
			ITEM 1A. RISK FACTORS
			ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
			ITEM 5. OTHER INFORMATION
			ITEM 6. EXHIBITS
			SIGNATURES


		(Unaudited)							(Unaudited)
		Three Months Ended March 31,							Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	(in millions, except per share amounts)	2020		2019		(in millions, except per share amounts)	2020		2019		2020		2019
Operating Revenues	Operating Revenues					Operating Revenues
Electric	Electric	$	3,040	$	2,792	Electric	$	3,435	$	2,946	$	6,475	$	5,738
Natural gas	Natural gas	1,266		1,219		Natural gas	1,098		997		2,364		2,216
Total operating revenues	Total operating revenues	4,306		4,011		Total operating revenues	4,533		3,943		8,839		7,954
Operating Expenses	Operating Expenses					Operating Expenses
Cost of electricity	Cost of electricity	545		599		Cost of electricity	759		837		1,304		1,436
Cost of natural gas	Cost of natural gas	284		339		Cost of natural gas	134		108		418		447
Operating and maintenance	Operating and maintenance	1,967		2,087		Operating and maintenance	2,141		1,942		4,108		4,029
Wildfire-related claims, net of insurance recoveries						Wildfire-related claims, net of insurance recoveries	170		3,900		170		3,900
Wildfire fund expense						Wildfire fund expense	173		—		173		—
Depreciation, amortization, and decommissioning	Depreciation, amortization, and decommissioning	855		797		Depreciation, amortization, and decommissioning	874		796		1,729		1,593
Total operating expenses	Total operating expenses	3,651		3,822		Total operating expenses	4,251		7,583		7,902		11,405
Operating Income		655		189
Operating Income (Loss)						Operating Income (Loss)	282		(3,640)		937		(3,451)
Interest income	Interest income	16		22		Interest income	12		22		28		44
Interest expense	Interest expense	(254)		(103)		Interest expense	(199)		(60)		(453)		(163)
Other income, net	Other income, net	97		71		Other income, net	100		66		197		137
Reorganization items, net	Reorganization items, net	(176)		(127)		Reorganization items, net	(1,624)		(56)		(1,800)		(183)
Income Before Income Taxes		338		52
Income tax benefit		(36)		(84)
Net Income		374		136
Loss Before Income Taxes						Loss Before Income Taxes	(1,429)		(3,668)		(1,091)		(3,616)
Income tax provision (benefit)						Income tax provision (benefit)	539		(1,119)		503		(1,203)
Net Loss						Net Loss	(1,968)		(2,549)		(1,594)		(2,413)
Preferred stock dividend requirement of subsidiary	Preferred stock dividend requirement of subsidiary	3		—		Preferred stock dividend requirement of subsidiary	4		4		7		7
Income Available for Common Shareholders		$	371	$	136
Loss Attributable to Common Shareholders						Loss Attributable to Common Shareholders	$	(1,972)	$	(2,553)	$	(1,601)	$	(2,420)
Weighted Average Common Shares Outstanding, Basic	Weighted Average Common Shares Outstanding, Basic	529		526		Weighted Average Common Shares Outstanding, Basic	529		529		529		528
Weighted Average Common Shares Outstanding, Diluted	Weighted Average Common Shares Outstanding, Diluted	648		527		Weighted Average Common Shares Outstanding, Diluted	529		529		529		528
Net Income Per Common Share, Basic		$	0.70	$	0.25
Net Income Per Common Share, Diluted		$	0.57	$	0.25
Net Loss Per Common Share, Basic						Net Loss Per Common Share, Basic	$	(3.73)	$	(4.83)	$	(3.03)	$	(4.58)
Net Loss Per Common Share, Diluted						Net Loss Per Common Share, Diluted	$	(3.73)	$	(4.83)	$	(3.03)	$	(4.58)

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.									See accompanying Notes to the Condensed Consolidated Financial Statements.


	(Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2020		2019		2020		2019
Net Loss	$	(1,968)	$	(2,549)	$	(1,594)	$	(2,413)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	—		—		—		—
Total other comprehensive income	—		—		—		—
Comprehensive Loss	(1,968)		(2,549)		(1,594)		(2,413)
Preferred stock dividend requirement of subsidiary	4		4		7		7
Comprehensive Loss Attributable to Common Shareholders	$	(1,972)	$	(2,553)	$	(1,601)	$	(2,420)

See accompanying Notes to the Condensed Consolidated Financial Statements.


	(Unaudited)
	Three Months Ended March 31,
(in millions)	2020		2019
Net Income	$	374	$	136
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)	—		—
Total other comprehensive income	—		—
Comprehensive Income	374		136
Preferred stock dividend requirement of subsidiary	3		—
Comprehensive Income Available for Common Shareholders	$	371	$	136

See accompanying Notes to the Condensed Consolidated Financial Statements.


	(Unaudited)
	Balance At
(in millions)	June 30, 2020		December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	$	968	$	1,570
Restricted cash	14,413		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $81 and $43 at respective dates)	1,419		1,287
Accrued unbilled revenue	1,061		969
Regulatory balancing accounts	2,638		2,114
Other	2,618		2,617
Regulatory assets	377		315
Inventories:
Gas stored underground and fuel oil	89		97
Materials and supplies	564		550
Wildfire fund asset	466		—
Other	400		639
Total current assets	25,013		10,165
Property, Plant, and Equipment
Electric	64,832		62,707
Gas	23,371		22,688
Construction work in progress	2,615		2,675
Other	20		20
Total property, plant, and equipment	90,838		88,090
Accumulated depreciation	(27,437)		(26,455)
Net property, plant, and equipment	63,401		61,635
Other Noncurrent Assets
Regulatory assets	7,507		6,066
Nuclear decommissioning trusts	3,196		3,173
Operating lease right of use asset	2,127		2,286
Wildfire fund asset	6,048		—
Income taxes receivable	67		67
Other	1,870		1,804
Total other noncurrent assets	20,815		13,396
TOTAL ASSETS	$	109,229	$	85,196

See accompanying Notes to the Condensed Consolidated Financial Statements.


2019 Form 10-K			PG&E Corporation and Pacific Gas and Electric Company’s combined Annual Report on Form 10-K for the year ended December 31, 2019
2019 Wildfire Mitigation Plan			the wildfire mitigation plan for 2019 submitted by the Utility to the CPUC pursuant to SB 901, previously also referred to as the “2019 Wildfire Safety Plan”
AB			Assembly Bill
ABR			alternate base rate
ALJ			administrative law judge
ARO			asset retirement obligation
ASU			accounting standard update issued by the FASB (see below)
Backstop Party			a third-party investor party to a Backstop Commitment Letter
Bankruptcy Code			the United States Bankruptcy Code
Bankruptcy Court			the U.S. Bankruptcy Court for the Northern District of California
CAISO			California Independent System Operator
Cal Fire			California Department of Forestry and Fire Protection
CARB			California Air Resources Board
CARE			California Alternate Rates for Energy
CCA			Community Choice Aggregator
CEMA			Catastrophic Event Memorandum Account
Chapter 11			chapter 11 of title 11 of the U.S. Code
Chapter 11 Cases			the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
CHT			Customer Harm Threshold
CPUC			California Public Utilities Commission
CPPMA			COVID-19 Pandemic Protections Memorandum Account
CRRs			congestion revenue rights
CUE			Coalition of California Utility Employees
CVA			Climate Vulnerability Assessment
DA			Direct Access
Diablo Canyon			Diablo Canyon nuclear power plant
DIP Credit Agreement			Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, and Citibank, N.A., as collateral agent
DTSC			Department of Toxic Substances Control
EPS			earnings per common share
Effective Date			July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
FASB			Financial Accounting Standards Board
FEMA			Federal Emergency Management Agency
FERC			Federal Energy Regulatory Commission
FHPMA			Fire Hazard Prevention Memorandum Account
FRMMA			Fire Risk Mitigation Memorandum Account
Fire Victim Trust			trust to be established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) is to be funded
GAAP			U.S. Generally Accepted Accounting Principles
GRC			general rate case
GT&S			gas transmission and storage


HSM			Hazardous Substance Memorandum Account
IOU(s)			investor-owned utility(ies)
LIBOR			London Interbank Offered Rate
LSTC			liabilities subject to compromise


MD&A			Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q
MGP(s)			manufactured gas plants
the Monitor			third-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAV			net asset value
NDCTP			Nuclear Decommissioning Cost Triennial Proceedings
NEIL			Nuclear Electric Insurance Limited
NRC			Nuclear Regulatory Commission
OES			State of California Office of Emergency Services
OII			order instituting investigation
OIR			order instituting rulemaking
PCIA			Power Charge Indifference Adjustment
POD			Presiding Officer’s Decision
PD			proposed decision
Petition Date			January 29, 2019
~~PFM~~			~~petition for modification~~
PSA			plan support agreement
PSPS			Public Safety Power Shutoff
RA			resource adequacy
ROE			return on equity
RSA			restructuring support agreement (as amended)
SB			Senate Bill
SEC			U.S. Securities and Exchange Commission
SED			Safety and Enforcement Division of the CPUC
Tax Act			Tax Cuts and Jobs Act of 2017
TCC			Official Committee of Tort Claimants
TO			transmission owner
TURN			The Utility Reform Network
Utility			Pacific Gas and Electric Company
VIE(s)			variable interest entity(ies)
WEMA			Wildfire Expense Memorandum Account
Wildfire Assistance Fund			program designed to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of temporary housing and other urgent needs
Wildfire Fund			statewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
Wildfires OII			Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire
WMP			Wildfire Mitigation Plan
WMPMA			Wildfire Mitigation Plan Memorandum Account


	(Unaudited)
	Balance At
(in millions, except share amounts)	June 30, 2020		December 31, 2019
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	300	$	—
Long-term debt, classified as current	450		—
Debtor-in-possession financing, classified as current	2,000		1,500
Accounts payable:
Trade creditors	3,399		1,954
Regulatory balancing accounts	1,915		1,797
Other	631		566
Operating lease liabilities	551		556
Interest payable	1,363		4
Disputed claims and customer refunds	238		—
Wildfire-related claims	26,143		—
Wildfire fund liability	5,200		—
Other	3,605		1,254
Total current liabilities	45,795		7,631
Noncurrent Liabilities
Long-term debt	34,920		—
Regulatory liabilities	9,641		9,270
Pension and other post-retirement benefits	1,941		1,884
Asset retirement obligations	5,961		5,854
Deferred income taxes	1,171		320
Operating lease liabilities	1,576		1,730
Other	4,423		2,573
Total noncurrent liabilities	59,633		21,631
Liabilities Subject to Compromise	—		50,546
Equity
Shareholders’ Equity
Common stock, 0 par value, authorized 3,600,000,000 and 800,000,000 shares at respective dates; 529,793,355 and 529,236,741 shares outstanding at respective dates	13,045		13,038
Reinvested earnings	(9,486)		(7,892)
Accumulated other comprehensive loss	(10)		(10)
Total shareholders’ equity	3,549		5,136
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	3,801		5,388
TOTAL LIABILITIES AND EQUITY	$	109,229	$	85,196

See accompanying Notes to the Condensed Consolidated Financial Statements.


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	—	$	(21)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	273	$	836
Operating lease liabilities arising from obtaining right-of-use assets	13		2,816

See accompanying Notes to the Condensed Consolidated Financial Statements.


(in millions, except share amounts)	(in millions, except share amounts)	Common Stock Shares	Common Stock Amount		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity		Non controlling Interest - Preferred Stock of Subsidiary		Total Equity		(in millions, except share amounts)	Common Stock Shares	Common Stock Amount		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity		Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
Balance at December 31, 2019	Balance at December 31, 2019	529,236,741	$	13,038	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388	Balance at December 31, 2019	529,236,741	$	13,038	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388
Net income	Net income	—	—		374		—		374		—		374		Net income	—	—		374		—		374		—		374
Other comprehensive loss	Other comprehensive loss	—	—		—		—		—		—		—		Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	Common stock issued, net	549,155	—		—		—		—		—		—		Common stock issued, net	549,155	—		—		—		—		—		—
Stock-based compensation amortization	Stock-based compensation amortization	—	(3)		—		—		(3)		—		(3)		Stock-based compensation amortization	—	(3)		—		—		(3)		—		(3)
Balance at March 31, 2020	Balance at March 31, 2020	529,785,896	$	13,035	$	(7,518)	$	(10)	$	5,507	$	252	$	5,759	Balance at March 31, 2020	529,785,896	$	13,035	$	(7,518)	$	(10)	$	5,507	$	252	$	5,759
Net loss															Net loss	—	—		(1,968)		—		(1,968)		—		(1,968)
Other comprehensive loss															Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net															Common stock issued, net	7,459	—		—		—		—		—		—
Stock-based compensation amortization															Stock-based compensation amortization	—	10		—		—		10		—		10
Balance at June 30, 2020															Balance at June 30, 2020	529,793,355	$	13,045	$	(9,486)	$	(10)	$	3,549	$	252	$	3,801


	(Unaudited)
	Balance At
(in millions. except share amounts)	June 30, 2020		December 31, 2019
LIABILITIES AND EQUITY
Current Liabilities
Long-term debt, classified as current	$	100	$	—
Debtor-in-possession financing, classified as current	2,000		1,500
Accounts payable:
Trade creditors	3,382		1,949
Regulatory balancing accounts	1,915		1,797
Other	717		675
Operating lease liabilities	548		553
Interest payable	1,331		4
Disputed claims and customer refunds	238		—
Wildfire-related claims	26,143		—
Wildfire fund liability	5,200		—
Other	1,579		1,263
Total current liabilities	43,153		7,741
Noncurrent Liabilities
Long-term debt	30,263		—
Regulatory liabilities	9,641		9,270
Pension and other post-retirement benefits	1,836		1,884
Asset retirement obligations	5,961		5,854
Deferred income taxes	1,316		442
Operating lease liabilities	1,573		1,726
Other	4,455		2,626
Total noncurrent liabilities	55,045		21,802
Liabilities Subject to Compromise	—		49,736
Shareholders’ Equity
Preferred stock	258		258
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates	1,322		1,322
Additional paid-in capital	8,550		8,550
Reinvested earnings	(4,818)		(4,796)
Accumulated other comprehensive income	1		1
Total shareholders’ equity	5,313		5,335
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	103,511	$	84,614

See accompanying Notes to the Condensed Consolidated Financial Statements.


(in millions)	Preferred Stock		Common Stock Amount		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity
Balance at December 31, 2019	$	258	$	1,322	$	8,550	$	(4,796)	$	1	$	5,335
Net income	—		—		—		451		—		451
Balance at March 31, 2020	$	258	$	1,322	$	8,550	$	(4,345)	$	1	$	5,786
Net loss	—		—		—		(473)		—		(473)
Balance at June 30, 2020	$	258	$	1,322	$	8,550	$	(4,818)	$	1	$	5,313


(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Financing debt⁽²⁾	$	22,450	$	666	$	23,116
Wildfire-related claims⁽³⁾	25,548		—		25,548
Trade creditors	1,183		5		1,188
Non-qualified benefit plan	20		137		157
2001 bankruptcy disputed claims ⁽⁴⁾	234		—		234
Customer deposits & advances	71		—		71
Other	230		2		232
Total Liabilities Subject to Compromise	$	49,736	$	810	$	50,546


	Three Months Ended March 31, 2020
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	3	$	—	$	3
Legal and other ⁽²⁾	95		84		179
Interest income	(5)		(1)		(6)
Total reorganization items, net	$	93	$	83	$	176


	Petition Date Through March 31, 2020
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	98	$	17	$	115
Legal and other ⁽²⁾	371		102		473
Interest income	(55)		(11)		(66)
Total reorganization items, net	$	414	$	108	$	522


	Three Months Ended March 31, 2019
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	23		1		24
Interest income	(9)		(2)		(11)
Total reorganization items, net	$	111	$	16	$	127


	Three Months Ended June 30, 2020
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	1	$	—	$	1
Legal and other ⁽²⁾	109		1,513		1,622
Interest income	—		—		—
Trustee fees ⁽³⁾	1		—		1
Total reorganization items, net	$	111	$	1,513	$	1,624


	Six Months Ended June 30, 2020
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	3	$	—	$	3
Legal and other ⁽²⁾	205		1,597		1,802
Interest income	(5)		(2)		(7)
Trustee fees ⁽³⁾	1		1		2
Total reorganization items, net	$	204	$	1,596	$	1,800


	Three Months Ended June 30, 2019
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	75		1		76
Interest income	(18)		(3)		(21)
Trustee fees ⁽²⁾	—		1		1
Total reorganization items, net	$	57	$	(1)	$	56


	Petition Date Through June 30, 2019
(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	98		2		100
Interest income	(27)		(5)		(32)
Trustee fees ⁽²⁾	—		1		1
Total reorganization items, net	$	168	$	15	$	183


		Pension Benefits						Other Benefits							Pension Benefits				Other Benefits
		Three Months Ended March 31,															Three Months Ended June 30,
(in millions)	(in millions)	2020		2019		2020		2019		(in millions)	2020		2019		2020		2019
Service cost for benefits earned⁽¹⁾	Service cost for benefits earned⁽¹⁾	$	132	$	111	$	15	$	14	Service cost for benefits earned⁽¹⁾	$	132	$	111	$	16	$	14
Interest cost	Interest cost	178		189		16		19		Interest cost	179		190		15		19
Expected return on plan assets	Expected return on plan assets	(261)		(227)		(34)		(31)		Expected return on plan assets	(261)		(226)		(35)		(30)
Amortization of prior service cost	Amortization of prior service cost	(1)		(1)		3		4		Amortization of prior service cost	(2)		(2)		4		3
Amortization of net actuarial loss	Amortization of net actuarial loss	1		1		(5)		(1)		Amortization of net actuarial loss	1		—		(5)		(1)
Net periodic benefit cost	Net periodic benefit cost	49		73		(5)		5		Net periodic benefit cost	49		73		(5)		5
Regulatory account transfer⁽²⁾	Regulatory account transfer⁽²⁾	34		10		—		—		Regulatory account transfer⁽²⁾	34		10		—		—
Total	Total	$	83	$	83	$	(5)	$	5	Total	$	83	$	83	$	(5)	$	5


		Pension Benefits		Other Benefits		Total			Pension Benefits		Other Benefits			Total
(in millions, net of income tax)	(in millions, net of income tax)	Three Months Ended March 31, 2020											(in millions, net of income tax)	Three Months Ended June 30, 2020
Beginning balance	Beginning balance	$	(22)	$	17	$	(5)	Beginning balance	$	(22)	$	17		$	(5)
Amounts reclassified from other comprehensive income:⁽¹⁾	Amounts reclassified from other comprehensive income:⁽¹⁾							Amounts reclassified from other comprehensive income:⁽¹⁾
Amortization of prior service cost (net of taxes of $0 and $1, respectively)		(1)		2		1
Amortization of net actuarial loss (net of taxes of $0 and $2, respectively)		1		(3)		(2)
Regulatory account transfer (net of taxes of $0 and $1, respectively)		—		1		1
Amortization of prior service cost (net of taxes of $1 and $1, respectively)								Amortization of prior service cost (net of taxes of $1 and $1, respectively)	(1)		3			2
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)								Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)	—		(4)			(4)
Regulatory account transfer (net of taxes of $0 and $0, respectively)								Regulatory account transfer (net of taxes of $0 and $0, respectively)	1		1			2
Net current period other comprehensive gain (loss)	Net current period other comprehensive gain (loss)	—		—		—		Net current period other comprehensive gain (loss)	—		—			—
Ending balance	Ending balance	$	(22)	$	17	$	(5)	Ending balance	$	(22)	$	17		$	(5)


		Receivable Balance at							Receivable Balance at
(in millions)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	June 30, 2020		December 31, 2019
Electric distribution	Electric distribution	$	213	$	—	Electric distribution	$	255	$	—
Electric transmission	Electric transmission	—		9		Electric transmission	—		9
Gas distribution and transmission	Gas distribution and transmission	45		363		Gas distribution and transmission	119		363
Energy procurement	Energy procurement	881		901		Energy procurement	1,300		901
Public purpose programs	Public purpose programs	288		209		Public purpose programs	216		209
Other	Other	675		632		Other	748		632
Total regulatory balancing accounts receivable	Total regulatory balancing accounts receivable	$	2,102	$	2,114	Total regulatory balancing accounts receivable	$	2,638	$	2,114


		Payable Balance at							Payable Balance at
(in millions)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	June 30, 2020		December 31, 2019
Electric distribution	Electric distribution	$	—	$	31	Electric distribution	$	—	$	31
Electric transmission	Electric transmission	148		119		Electric transmission	197		119
Gas distribution and transmission	Gas distribution and transmission	74		45		Gas distribution and transmission	33		45
Energy procurement	Energy procurement	585		649		Energy procurement	731		649
Public purpose programs	Public purpose programs	565		559		Public purpose programs	547		559
Other	Other	473		394		Other	407		394
Total regulatory balancing accounts payable	Total regulatory balancing accounts payable	$	1,845	$	1,797	Total regulatory balancing accounts payable	$	1,915	$	1,797


(in millions)	(in millions)	Termination Date		Aggregate Limit		Term Loan Borrowings		Revolver Borrowings		Letters of Credit Outstanding		Aggregate Availability		(in millions)	Termination Date	Aggregate Limit		Term Loan Borrowings		Revolver Borrowings		Letters of Credit Outstanding		Aggregate Availability
DIP Facilities	DIP Facilities	December 2020	(1)	$	5,500	$	2,000	$	—	$	774	$	2,726	DIP Facilities	December 2020	$	5,500	$	2,000	$	—	$	904	$	2,596


		Balance at
(in millions)	Contractual Interest Rates	March 31, 2020		December 31, 2019		Treatment under Plan ⁽¹⁾
Debt Subject to Compromise⁽²⁾
PG&E Corporation
Borrowings under Pre-Petition Credit Facility
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022	variable rate⁽³⁾	$	300	$	300	Repaid in cash
Other borrowings
Term Loan - Stated Maturity: 2020	variable rate ⁽⁴⁾	350		350		Repaid in cash
Total PG&E Corporation Debt Subject to Compromise		650		650

Utility
Senior Notes - Stated Maturity:
2020	3.50%	800		800		Exchanged for New Utility Short-Term Notes
2021	3.25% to 4.25%	550		550		Exchanged for New Utility Short-Term Notes
2022	2.45%	400		400		Exchanged for New Utility Short-Term Notes
2023	3.25% to 4.25%	1,175		1,175		Reinstated
2024 through 2028	2.95% to 4.65%	3,850		3,850		Reinstated
2034 through 2040	5.40% to 6.35%	5,700		5,700		Exchanged for New Utility Long-Term Notes
2041 through 2042	3.75% to 4.50%	1,000		1,000		Reinstated
2043	4.60%	375		375		Reinstated
2043	5.13%	500		500		Exchanged for New Utility Long-Term Notes
2044 through 2047	3.95% to 4.75%	3,175		3,175		Reinstated
Total Senior notes		17,525		17,525
Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026⁽⁵⁾	1.75%	100		100		Repaid in cash
Series 2009 A-B, due 2026⁽⁶⁾	variable rate ⁽⁷⁾	149		149		Exchanged for New Utility Funded Debt Exchange Notes
Series 1996 C, E, F, 1997 B due 2026⁽⁶⁾	variable rate ⁽⁸⁾	614		614		Exchanged for New Utility Funded Debt Exchange Notes
Total pollution control bonds		863		863
Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022 ⁽⁹⁾	variable rate ⁽¹⁰⁾	2,888		2,888		Exchanged for New Utility Funded Debt Exchange Notes
Other borrowings:
Term Loan - Stated Maturity: 2019	variable rate ⁽¹¹⁾	250		250		Exchanged for New Utility Funded Debt Exchange Notes
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise		3,138		3,138
Total Utility Debt Subject to Compromise		21,526		21,526
Total PG&E Corporation Consolidated Debt Subject to Compromise		$	22,176	$	22,176


Utility
First Mortgage Bonds - Stated Maturity:
2022	variable rate ⁽¹¹⁾	500		—
2022	1.75%	2,500		—
2027	2.10%	1,000		—
2031	2.50%	2,000		—
2040	3.30%	1,000		—
2050	3.50%	1,925		—
Unamortized discount, net of premium and debt issuance costs		(88)		—
Total Utility New Debt		8,837		—
Total PG&E Corporation Consolidated New Debt		$	13,494	$	—

Total Utility Long-Term Debt		$	30,263
Total PG&E Corporation Consolidated Long-Term Debt		$	34,920


			Contract Volume at					Contract Volume at
Underlying Product	Underlying Product	Instruments	March 31, 2020	December 31, 2019	Underlying Product	Instruments	June 30, 2020	December 31, 2019
Natural Gas ⁽¹⁾ (MMBtus ⁽²⁾)	Natural Gas ⁽¹⁾ (MMBtus ⁽²⁾)	Forwards, Futures and Swaps	138,102,835	131,896,159	Natural Gas ⁽¹⁾ (MMBtus ⁽²⁾)	Forwards, Futures and Swaps	199,547,057	131,896,159
		Options	7,760,000	14,720,000		Options	33,810,000	14,720,000
Electricity (Megawatt-hours)	Electricity (Megawatt-hours)	Forwards, Futures and Swaps	49,291,087	18,675,852	Electricity (Megawatt-hours)	Forwards, Futures and Swaps	9,754,771	18,675,852
		Options	4,414,400	—		Options	1,620,000	—
		Congestion Revenue Rights ⁽³⁾	298,648,904	308,467,999		Congestion Revenue Rights ⁽³⁾	287,183,280	308,467,999


		Commodity Risk															Commodity Risk
(in millions)	(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance		(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	Current assets – other	$	35	$	(6)	$	11	$	40	Current assets – other	$	46	$	(7)	$	29	$	68
Other noncurrent assets – other	Other noncurrent assets – other	133		—		—		133		Other noncurrent assets – other	121		—		—		121
Current liabilities – other	Current liabilities – other	(31)		6		1		(24)		Current liabilities – other	(44)		7		—		(37)
Noncurrent liabilities – other	Noncurrent liabilities – other	(138)		—		—		(138)		Noncurrent liabilities – other	(183)		—		—		(183)
Total commodity risk	Total commodity risk	$	(1)	$	—	$	12	$	11	Total commodity risk	$	(60)	$	—	$	29	$	(31)


		Fair Value Measurements																			Fair Value Measurements
		March 31, 2020																			June 30, 2020
(in millions)	(in millions)	Level 1		Level 2		Level 3		Netting ⁽¹⁾		Total		(in millions)	Level 1		Level 2		Level 3		Netting ⁽¹⁾		Total
Assets:	Assets:											Assets:
Short-term investments	Short-term investments	$	1,717	$	—	$	—	$	—	$	1,717	Short-term investments	$	718	$	—	$	—	$	—	$	718
Nuclear decommissioning trusts	Nuclear decommissioning trusts											Nuclear decommissioning trusts
Short-term investments	Short-term investments	82		—		—		—		82		Short-term investments	34		—		—		—		34
Global equity securities	Global equity securities	1,792		—		—		—		1,792		Global equity securities	2,135		—		—		—		2,135
Fixed-income securities	Fixed-income securities	784		734		—		—		1,518		Fixed-income securities	794		753		—		—		1,547
Assets measured at NAV	Assets measured at NAV	—		—		—		—		17		Assets measured at NAV	—		—		—		—		20
Total nuclear decommissioning trusts ⁽²⁾	Total nuclear decommissioning trusts ⁽²⁾	2,658		734		—		—		3,409		Total nuclear decommissioning trusts ⁽²⁾	2,963		753		—		—		3,736
Price risk management instruments (Note 8)	Price risk management instruments (Note 8)											Price risk management instruments (Note 8)
Electricity	Electricity	—		7		159		5		171		Electricity	—		14		148		21		183
Gas	Gas	—		2		—		—		2		Gas	—		5		—		1		6
Total price risk management instruments	Total price risk management instruments	—		9		159		5		173		Total price risk management instruments	—		19		148		22		189
Rabbi trusts	Rabbi trusts											Rabbi trusts
Fixed-income securities	Fixed-income securities	—		102		—		—		102		Fixed-income securities	—		105		—		—		105
Life insurance contracts	Life insurance contracts	—		76		—		—		76		Life insurance contracts	—		77		—		—		77
Total rabbi trusts	Total rabbi trusts	—		178		—		—		178		Total rabbi trusts	—		182		—		—		182
Long-term disability trust	Long-term disability trust											Long-term disability trust
Short-term investments	Short-term investments	6		—		—		—		6		Short-term investments	6		—		—		—		6
Assets measured at NAV	Assets measured at NAV	—		—		—		—		157		Assets measured at NAV	—		—		—		—		150
Total long-term disability trust	Total long-term disability trust	6		—		—		—		163		Total long-term disability trust	6		—		—		—		156
TOTAL ASSETS	TOTAL ASSETS	$	4,381	$	921	$	159	$	5	$	5,640	TOTAL ASSETS	$	3,687	$	954	$	148	$	22	$	4,981
Liabilities:	Liabilities:											Liabilities:
Equity Backstop Commitments and Forward Stock Purchase Agreements												Equity Backstop Commitments and Forward Stock Purchase Agreements	$	—	$	1,500	$	—	$	—	$	1,500
Price risk management instruments (Note 8)	Price risk management instruments (Note 8)											Price risk management instruments (Note 8)
Electricity	Electricity	$	—	$	5	$	164	$	(7)	$	162	Electricity	—		9		214		(6)		217
Gas	Gas	—		—		—		—		—		Gas	—		4		—		(1)		3
TOTAL LIABILITIES	TOTAL LIABILITIES	$	—	$	5	$	164	$	(7)	$	162	TOTAL LIABILITIES	$	—	$	1,513	$	214	$	(7)	$	1,720


	Price Risk Management Instruments
(in millions)	2020		2019
Asset balance as of January 1	$	5	$	95
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts ⁽¹⁾	(10)		34
Asset balance as of March 31	$	(5)	$	129


		At March 31, 2020						At December 31, 2019							At June 30, 2020				At December 31, 2019
(in millions)	(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value		(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount⁽¹⁾		Level 2 Fair Value⁽¹⁾⁽²⁾
Debt (Note 5)	Debt (Note 5)									Debt (Note 5)
PG&E Corporation⁽¹⁾	PG&E Corporation⁽¹⁾	$	—	$	—	$	—	$	—	PG&E Corporation⁽¹⁾	$	2,257	$	2,005	$	—	$	—
Utility⁽²⁾	Utility⁽²⁾	2,000		2,007		1,500		1,500		Utility⁽²⁾	25,962		28,853		1,500		1,500


	As of
(in millions)	~~March 31,~~June 30, 2020
Less than 1 year	$	2628
1–5 years	~~397~~416
5–10 years	~~408~~404
More than 10 years	~~687~~699
Total maturities of fixed-income securities	$	~~1,518~~1,547


Insurance Receivable (in millions)	2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	1,380	$	807	$	50	$	2,237
Accrued insurance recoveries	430		—		—		—		430
Reimbursements	—		(408)		(121)		—		(529)
Balance at June 30, 2020	$	430	$	972	$	686	$	50	$	2,138