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,~~receivables, 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 and Safety 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~~2020 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~~2020 Form 10-K. This quarterly report should be read in conjunction with the ~~2019~~2020 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.

On ~~January 29, 2019,~~the Petition Date, 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~~On June 20, 2020, the Bankruptcy ~~Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or~~Court entered the ~~Utility, as well as most litigation pending against~~Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility ~~(including~~emerged from Chapter 11 on the ~~third-party matters described~~Effective Date of July 1, 2020.

Except as otherwise set forth in ~~Note 10 below) as of~~ the ~~Petition Date, are subject to an automatic stay. Absent an~~Plan, the Confirmation Order or another order of the Bankruptcy Court, ~~providing otherwise,~~ substantially all pre-petition liabilities ~~will be resolved under a Chapter 11 plan of reorganization to be voted upon by impaired creditors and interest holders, and approved by the Bankruptcy Court. However,~~were discharged under the ~~Bankruptcy Code, regulatory or criminal proceedings generally are not subject to an automatic stay, and these proceedings have been continuing during the pendency of the Chapter 11 Cases.~~

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

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

However, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility ~~believe~~on or after the Effective Date, including but not limited to, claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that ~~such claims will~~began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”).

In addition, Subordinated Debt Claims and Holdco Rescission or Damage Claims continue to be ~~allowed by the Bankruptcy Court,~~pursued against PG&E Corporation and the Utility ~~will continue to record~~in the ~~expected allowed amounts of such~~ claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as ~~liabilities subject to compromise. The determination of~~well as certain underwriters, are being pursued in the ~~expected allowed amount of a claim~~purported securities class action that is based on many factors, including whether PG&E Corporation or the Utility is party to a settlement 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 the TCC,” “Restructuring Support Agreements with Holders of Subrogation Claims,” and “Plan Support Agreements with Public Entities”further described in Note 10 ofunder the Notes to the Condensed Consolidated Financial Statements for more information on settlement of wildfire-related claims, and “Restructuring Support Agreement with the Ad Hoc Noteholder Committee” in Note 2 of the Notes to the Condensed Consolidated Financial Statements for more information on settlement of Utility debt claims. As PG&E Corporation and the Utility continue to resolve claims, differences between those final allowed claims and the liabilities recorded in the Condensed Consolidated Balance Sheet will be recognized in PG&E Corporation’s and the Utility’s Statement of Consolidated Income (Loss) as they are resolved. The determination of how liabilities will ultimately be resolved cannot be made until the Bankruptcy Court approves a plan of reorganization or approves orders related to settlement of specific liabilities. Accordingly, the ultimate amount or resolution of such liabilities is not determinable at this time. The resolution of such claims could result in substantial adjustments to PG&E Corporation’s and the Utility’s financial statements.heading “Securities Class Action Litigation.”

On September 1, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court requesting that the court approve an alternative dispute resolution process for resolving disputed general unsecured claims and appoint a panel of mediators in the process. On September 25, 2020, the court approved the motion and appointed a panel of mediators. The ~~Utility’s obligations with respect~~mediators’ role will be to ~~such~~assist various claims ~~(all~~through a Standard and Abbreviated Mediation Process.

On October 27, 2020, PG&E Corporation and the Utility filed a motion for entry of an order extending the deadline for PG&E Corporation and the Utility to object to claims, requesting an additional 180 days beyond December 31, 2020 to process claims. On April 5, 2021, the Bankruptcy Court entered an order further extending the deadline to object to claims through and including December 23, 2021, except for certain claims filed by Cal Fire, for which ~~arose prior~~the deadline is September 30, 2021, in each case without prejudice to the ~~initiation~~rights of PG&E Corporation and the ~~Utility’s pending Chapter 11 Case~~Utility to seek additional extensions thereof. By stipulation approved by the Bankruptcy Court, the objection deadline for certain claims asserted by the United States is July 30, 2021 or September 30, 2021, depending on ~~January 29, 2019), including pursuant to any prior settlements relating thereto, are expected to be determined through~~ the ~~proceedings~~claim.

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~~2020 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.

The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5) in October 2020 is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Condensed Consolidated Balance Sheets. As of March 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated.

The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the period ended March 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of March 31, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.5 billion and $2.6 billion, respectively, and outstanding borrowings of $650 million and $1.0 billion, respectively, under the Receivables Securitization Program.

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, ~~2020, the Utility~~2021, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at March 31, ~~2020,~~2021, 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.

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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.

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.~~will be combined in the 2023 GRC. 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.

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~~Intangibles—Goodwill~~The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and ~~Other~~(iii) $300 million in annual contributions paid by California’s three large electric IOUs for at least a 10 year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from customers. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million).

~~In August 2018,~~On the ~~FASB issued ASU No. 2018-15,~~ ~~Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract.~~ Effective Date, PG&E Corporation and the Utility ~~adopted~~contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the ~~ASU~~Wildfire Fund to secure participation of the Utility therein. San Diego Gas & Electric Company and Southern California Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of March 31, 2021, PG&E Corporation and the Utility have 8 remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on ~~January 1, 2020.~~an estimated period of coverage.

As of March 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other non-current liabilities, $464 million in current assets - Wildfire Fund asset, and $5.7 billion in non-current assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended March 31, 2021, the Utility recorded amortization and accretion expense of $119 million. The ~~adoption~~amortization of ~~this ASU did not have a material impact~~the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Condensed Consolidated ~~Financial Statements~~Balance Sheets are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and ~~related disclosures.~~the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.

AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a 5 year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to 6 years. Similarly, a 10 percent change to the assumption regarding current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.

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

PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. At March 31, 2021, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.

PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. ~~In applying the new guidance,~~ PG&E Corporation and the Utility have incorporated forward-looking data in ~~its~~their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to ~~California unemployment rates.~~current economic conditions. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. During the three months ended March 31, 2021, expected credit losses of $76 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded during the three months ended March 31, 2021, $49 million and $7 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively.

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

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

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

In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million. SBA paid the Utility $946 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement through June 30, 2021.

The Utility recorded approximately $365 million of the $946 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $946 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a discounted cash flow model based on business assumptions and estimates to determine the allocation of the purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are presented within Other non-current liabilities on the Condensed Consolidated Balance Sheets.

The Utility recorded the remaining approximately $475 million ($471 million of which is noncurrent) of the sale proceeds to a regulatory liability, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices.

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

Long-term regulatory assets are comprised of the following:

Long-term regulatory liabilities are comprised of the following:

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

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2019~~2020 Form 10-K.

The following table summarizes PG&E Corporation’s and the Utility’s outstanding ~~debt subject~~borrowings and availability under their credit facilities at March 31, 2021:

In March 2021, the Utility issued $1.5 billion aggregate principal ~~amounts~~amount of 1.367% First Mortgage Bonds due March 10, 2023, $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and ~~not pre-petition or post-petition interest.~~$450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The ~~New Utility Short-Term Notes, New Utility Long-Term Senior Notes~~proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s term loan credit agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the revolving credit agreement and ~~New Utility Funded Debt Exchange Notes are described in more detail~~(iii) general corporate purposes.

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “Term Loan”) under ~~“Restructuring Support Agreement~~a term loan credit agreement (the “Term Loan Agreement”). The Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. In accordance with the ~~Ad Hoc Noteholder Committee”~~Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the Term Loan in ~~Note 2.~~an amount equal to $6.875 million on the last day of each quarter.

⁽²⁾~~Debt subject~~On February 1, 2021, PG&E Corporation entered into a repricing amendment with the lenders under the Term Loan Agreement pursuant to ~~compromise must be reported at~~which, among other things, the ~~amounts expected~~applicable margin was reduced from 450 basis points to ~~be allowed by the Bankruptcy Court~~300 basis points and the ~~carrying values will be adjusted as claims are approved. Total Debt Subject~~LIBOR floor was reduced from 100 basis points to Compromise does not include accrued contractual interest of $1 million and $286 million for PG&E Corporation and the Utility, respectively, to the Petition Date. Total Debt Subject to Compromise also does not include post-petition interest of $20 million and $815 million for PG&E Corporation and the Utility, respectively, in accordance with the terms of the Noteholder RSA. See Note 2 for further details.

~~Beginning January 1, 2019~~Under section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation ~~changed~~or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles of Incorporation (the “Amended Articles”) limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date 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 date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its ~~default matching contributions under its 401(k) plan from~~net operating loss carryforwards and other tax attributes are not limited by section 382 of the Internal Revenue Code.

In addition, the tax deduction recorded reflects PG&E Corporation’s conclusion as of March 31, 2021 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 transfers of cash and other property (including PG&E Corporation common ~~stock~~stock) were made to ~~cash. Beginning in March 2019, at PG&E Corporation’s directive,~~ the ~~401(k) plan trustee began purchasing new shares in the~~Fire Victim Trust. In January 2021, PG&E Corporation ~~common stock fund on~~received an IRS ruling that states the ~~open market~~Utility is eligible to make a grantor trust election for U.S. federal income tax purposes with respect to the Fire Victim Trust and addressed certain, but not all, related issues. PG&E Corporation believes benefits associated with “grantor trust” treatment, including, a potentially larger tax deduction related to the proceeds realized by the Fire Victim Trust from the sale of shares contributed to the Fire Victim Trust, could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock. PG&E Corporation expects to elect grantor trust treatment if it is able to enter into a definitive agreement regarding the same with the Fire Victim Trust. On April 28, 2021, the Bankruptcy Court issued an oral ruling that it would approve the material terms of an agreement between PG&E Corporation, the Utility and the Fire Victim Trust that supports the election of the grantor trust treatment. There can be no assurance that the parties will execute a definitive agreement or that PG&E Corporation will be able to avail itself of the benefits of a grantor trust election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur only at the time the Fire Victim Trust pays the fire victims and will be impacted by the price at which the Fire Victim Trust sells the shares, rather than ~~directly from PG&E Corporation.~~the price at the time such shares were contributed to the Fire Victim Trust.

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, due to the uncertainty related to the causes of and potential liabilities associated with wildfires. See Wildfire-related Contingencies in Note 10 below.~~2018.

~~The DIP Credit Agreement includes usual~~Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K, any decision to declare and ~~customary covenants for debtor-in-possession loan agreements~~pay dividends in the future will be made at the discretion of ~~this type, including covenants limiting PG&E Corporation’s~~the Boards of Directors and ~~the Utility’s ability to,~~will depend on, among other things, ~~declare~~results of operations, financial condition, cash requirements, contractual restrictions and ~~pay any dividend or make any~~ other ~~distributions with respect to any~~factors that the Boards of ~~their capital stock. Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions~~Directors may deem relevant. As of ~~probation, including foregoing issuing “any dividends until [the Utility]~~March 31, 2021, it is ~~in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s Wildfire Mitigation Plan. On March 20, 2020,~~uncertain when PG&E Corporation and the Utility ~~filed a Case Resolution Contingency Motion with~~will commence the ~~Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to~~payment of dividends on their common stock and when the ~~dividend restriction, PG&E Corporation “will not pay common~~Utility will commence the payment of 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.~~

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 of options and securities that were antidilutive.~~in periods where PG&E Corporation has incurred a net loss.

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, 2021, the Utility’s outstanding derivative balances were as follows:

At December 31, 2020, 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~~Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. ~~During~~Multiple credit agencies continue to rate the ~~first quarter of 2019, multiple credit rating agencies downgraded the Utility’s credit ratings~~Utility below investment grade, which ~~resulted~~results in the Utility posting additional collateral. As of March 31, ~~2020,~~2021, 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 months ended March 31, ~~2020~~2021 and ~~2019.~~2020.

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

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

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

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

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

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

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

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

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

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

The following table presents the reconciliation for Level 3 instruments for the three months ended March 31, ~~2020~~2021 and ~~2019:~~2020:

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, ~~2020~~2021 and December 31, ~~2019,~~2020, as they are short-term in nature.

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

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:

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 (as incorporated into the Plan) 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~~that has funded ~~into a trust (the “Fire~~and will fund the Fire Victim ~~Trust”) to be established~~Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims ~~and will consist~~consists of (a) $5.4 billion in cash that was contributed on the ~~effective date~~Effective Date of the Plan, (b) $1.35 billion in cash ~~comprising~~consisting of (i) ~~$650~~$758 million that was paid in cash on ~~or before~~ January 15, 2021 and (ii) ~~$700~~the remaining balance of $592 million 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,~~Tax Benefits Payment Agreement (as defined below), 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~~would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the ~~effective date~~Effective Date of the Plan, assuming the Utility’s ~~current~~ allowed ~~ROE. Under certain circumstances, including certain change~~ROE as of ~~control transactions~~the date of the TCC RSA. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation, the Utility, the TCC, and ~~in connection~~the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of PG&E Corporation on the Effective Date, subject to potential adjustments.

On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the ~~monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in (b) will be accelerated and payable upon an earlier date. The Aggregate~~ Fire Victim ~~Consideration also includes (1)~~Trust, pursuant to which the ~~assignment by PG&E Corporation and the~~ Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain ~~rights and causes of action~~tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 and (ii) of the ~~2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and~~remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022. On January 15, 2021, the Utility ~~may have against certain third parties and (2)~~paid the ~~assignment~~first tranche of ~~rights under the 2015 and 2016 insurance policies to resolve any claims related~~tax benefits of approximately $758 million pursuant to the ~~Fires in those policy years, other than the rights of PG&E Corporation and the Utility~~Tax Benefits Payment Agreement, leaving approximately $592 million to be ~~reimbursed under the 2015 insurance policies for claims submitted prior to the Petition Date.~~paid.

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

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

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~~The cause of the 2019 Kincade fire is under investigation by~~On July 16, 2020, Cal Fire ~~and the CPUC, and PG&E Corporation and the Utility are cooperating with those investigations. PG&E Corporation and the Utility are also conducting their own investigation into~~issued a press release addressing the cause of the 2019 Kincade fire. ~~This investigation is preliminary,~~The press release stated that Cal Fire 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.”

On April 6, 2021, the Sonoma County District Attorney’s office filed a criminal complaint (the “Complaint”) charging the Utility with 5 felonies and 28 misdemeanors related to the 2019 Kincade fire. The Complaint alleges 3 felony counts of recklessly causing a fire that caused great bodily injury to 6 firefighters and/or burned inhabited and other structures, inhabited property, forest land and personal property, in violation of Penal Code section 452; 2 felony counts of reckless emission of air contaminants that caused great bodily injury to 2 minors, in violation of Health and Safety Code section 42400.3(c); 1 misdemeanor count of carelessly or negligently throwing or placing substances that may cause a fire, in violation of Health and Safety Code section 13001; 1 misdemeanor count of negligently causing fire, in violation of Public Resources Code section 4421; 3 misdemeanor counts of violation by a public utility, in violation of Public Utilities Code section 2110; and 23 misdemeanor counts of recklessly or negligently emitting air contaminants, in violation of Health and Safety Code sections 42400.3(b) and 42400.1(a). If convicted of any of the charges in the Complaint, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorney's fees and interest), as well as non-monetary remedies such as oversight requirements.

On April 6, 2021, PG&E Corporation ~~and~~announced that it disputed the ~~Utility do~~charges in the Complaint. It further announced that it will accept Cal Fire’s finding that a PG&E transmission line caused the 2019 Kincade fire, even though PG&E Corporation does not have access to ~~all~~the evidence that Cal Fire gathered. On April 20, 2021, the court held an initial hearing in the case.

Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the ~~evidence in~~fire, contributing causes of the ~~possession~~fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of ~~Cal Fire~~structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other ~~third parties. There~~governmental entities.

If the Utility’s facilities, such as its electric distribution and transmission lines, are ~~a number of unknown facts surrounding~~judicially determined to be the substantial cause of the 2019 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 and~~reports, Cal Fire’s determination of the cause, other information gathered as part of PG&E Corporation’s and the Utility’s investigation, and the charges filed by the Sonoma County District Attorney’s Office, PG&E Corporation and the Utility believe it is ~~reasonably possible~~probable that they will incur a loss in connection with the 2019 Kincade fire. If PG&E Corporation and the Utility ~~were~~recorded a charge in the aggregate amount of $625 million for the year ended December 31, 2020 (before available insurance). Based on additional facts and circumstances available to ~~incur a loss in respect~~the Utility as of the ~~2019 Kincade fire,~~date of this filing, including the status of negotiations with certain subrogation entities and certain county and local agencies, PG&E Corporation and the Utility ~~estimate that~~recorded an additional charge for potential losses in connection with the ~~amount~~2019 Kincade fire of ~~such loss could exceed $600~~$175 million for the three months ended March 31, 2021, for an aggregate liability of $800 million (before available insurance). ~~This amount~~

The aggregate liability of $800 million for claims in connection with the 2019 Kincade fire (before available insurance) 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~~$800 million estimate ~~of the lower end of the range of reasonably possible losses~~ does not include, among other ~~things,~~things: (i) any amounts for potential penalties, fines, or ~~fines~~restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state ~~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.

Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges in the Complaint, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victim and is not offset by any compensation that the victims have received or may receive from their insurance carriers. In the event that the Utility were convicted of certain charges in the Complaint, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2019 Kincade fire would materially exceed the $800 million aggregate liability that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses for the 2019 Kincade fire civil claims. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding.

The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than ~~$600~~$800 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.~~Utility and the outcome of the criminal proceedings initiated against the Utility by the Sonoma County District Attorney’s Office. 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 the possession of Cal ~~Fire’s possession,~~Fire or the Sonoma County District Attorney’s Office, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of 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,~~2019 Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is ~~possible~~deemed probable that ~~facts could emerge that lead~~ recovery will occur, and the Utility can reasonably estimate the amount or its range. As of March 31, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

PG&E Corporation and the Utility ~~to believe that a loss is probable, resulting in~~have received data requests from the accrual of a liability at that time, the amount of which could be significant and may exceed the foregoing estimate of the lower end of the range of reasonably possible losses. For the reasons discussed above,SED relating to the 2019 Kincade fire ~~could~~and have ~~a material impact~~responded to all data requests received to date, and various other entities may also be investigating the fire. It is uncertain when any such investigations will be complete.

As of April 28, 2021, PG&E Corporation and the Utility are aware of 25 complaints on behalf of approximately 535 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s ~~financial condition, results~~alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of ~~operations, liquidity, and cash flows, as well as on~~ the ~~bankruptcy timing and process~~2019 Kincade fire. On December 3, 2020, PG&E Corporation and the ~~ability~~Utility filed a petition with the California Judicial Council to coordinate the litigation. On April 8, 2021, the coordination motion judge ordered that the cases be coordinated, and on April 16, 2021, the San Francisco County Superior Court was selected as the site of the ~~Utility to participate in the Wildfire Fund.~~coordinated proceeding.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2019 Kincade fire, including if PG&E Corporation or the Utility were found to have been negligent.

According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported 4 fatalities and 1 injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management.

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

On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo.

Cal Fire also indicated that its investigative report has been forwarded to the Shasta County District Attorney’s Office, which is investigating the matter. PG&E Corporation and the Utility have received and are responding to data requests from the ~~CPUC’s~~ SED and document requests from the Shasta County District Attorney’s Office relating to the ~~Kincade fire. Various~~2020 Zogg fire, and various other entities, ~~including~~which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when ~~the~~any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties.

Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the 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, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a charge in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with certain agencies and additional damages information from certain plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire in the amount of $25 million for the three months ended March 31, 2021, for an aggregate liability of $300 million (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above.

The aggregate liability of $300 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $300 million estimate does not include, among other things: (i) any amounts for potential penalties, fines or restitution that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, or (iv) 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 the loss will be greater than $300 million and 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 2020 Zogg 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. 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 personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties.

The process for estimating losses associated with potential claims related to the 2020 Zogg 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 2020 Zogg fire may change.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of March 31, 2021, the Utility has recorded an insurance receivable for $247 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $300 million probable loss estimate less an initial self-insured retention of $60 million, plus $7 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

As of April 28, 2021, PG&E Corporation and the Utility are aware of 7 complaints on behalf of approximately 266 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate 5 civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court. On March 15, 2021, PG&E Corporation and the Utility filed a brief that supported coordination but requested that the cases be coordinated in Shasta County Superior Court or, in the alternative, Sacramento County Superior Court. On March 24, 2021, pursuant to authorization from the California Judicial Council, a judge of the San Francisco County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for May 12, 2021.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2020 Zogg fire, including if PG&E Corporation and the Utility were found to have been negligent.

PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to ~~the 2018 Camp fire and 2017 Northern California~~ wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

In ~~2018,~~April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period of April 12, 2021 to April 1, 2022, and approximately $32 million in wildfire liability reinsurance for the period of April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire reinsurance for the period of July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period of August 1, 2020 to August 1, 2021. On August 1, 2021, this existing wildfire liability coverage is scheduled to renew for the period of August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million. For non-wildfire events, the Utility carries approximately $700 million in coverage for the period of August 1, 2020 to August 1, 2021 at a cost of approximately $152 million. At March 31, 2021, PG&E Corporation and the Utility ~~renewed their liability~~had prepaid insurance ~~coverage for wildfire events~~of $313 million, reflected in ~~an aggregate amount of approximately $1.4 billion for~~Other current assets on the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. In 2020, PG&E Corporation and the Utility has 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 from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation and the Utility continue to pursue additional insurance coverage. Condensed Consolidated Balance Sheets.

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

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

The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the ~~Utility expect to receive the~~amount of insurance ~~recoveries associated with the 2018 Camp fire and 2017 Northern California wildfires shortly after emergence from Chapter 11.~~coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.)

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through March 31, ~~2020,~~2021, PG&E Corporation and the Utility recorded ~~$1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $843~~$430 million for probable insurance recoveries in connection with the 2019 Kincade fire, and $247 million for probable insurance recoveries in connection with the 2020 Zogg fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. ~~These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies.~~ PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, PG&E Corporation and the Utility expect their losses in connection with the 2018 Camp fire and the 2017 Northern California wildfires will substantially exceed their available insurance.

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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~~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~~In connection with the proposed transaction, the Utility would retire $6.0 billion of ~~temporary~~ Utility debt and accelerate ~~a $700~~the remaining $592 million payment due to the Fire Victim Trust ~~post-Effective Date.~~(see “Restructuring Support Agreement with the TCC” above). On April 23, 2021, the CPUC issued a decision granting the Utility’s application for a $7.5 billion rate neutral securitization.

On April 5, 2021, the ALJ issued a PD granting the Utility’s application for a financing order authorizing the issuance of recovery bonds in connection with a post-emergence transaction. On April 26, 2021, the Utility filed opening comments on the PD. The Utility’s reply comments are due on May 3, 2021. The Utility expects a CPUC decision on the financing order by May 6, 2021.

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

For more information see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.

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

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

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

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the ~~previously-filed~~previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and former directors, and the underwriters. ~~The action remains stayed as to PG&E Corporation and the Utility.~~ On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are ~~currently~~ under submission with the District Court. The securities actions have been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with such claims to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases.

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available with respect to the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows:

PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date).

The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the ~~plaintiffs~~lead plaintiff filed a notice of appeal regarding the denial of ~~their~~its motion. On March 8, 2021, the District Court issued an order dismissing the appeal.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. The merits of the appeal are fully briefed. On February 16, 2021, the Committee of Tort Claimants filed a motion to dismiss PERA’s appeal. On March 9, 2021, PERA filed its opposition to the motion to dismiss, and on March 16, 2021, PG&E Corporation and the Utility filed a statement with respect to the motion to dismiss. The motion is scheduled to be heard on May 13, 2021.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to help facilitate the resolution of the Subordinated Claims. The motion, among other things, requested approval of procedures which allow PG&E Corporation and the Utility to collect certain trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion.

On September 28, 2020, PERA filed a second motion under Bankruptcy Rule 7023 requesting that the Bankruptcy Court allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”) seeking to position its motion as an alternative to the Securities Claims Procedures Motion. On December 4, 2020, the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, the Bankruptcy Court entered an order granting the Securities Claims Procedures Motion. On January 26, 2021, the Bankruptcy Court entered a written order denying the Renewed 7023 Motion.

PG&E Corporation and the Utility have been working to resolve the Subordinated Claims in accordance with the procedures approved by the Bankruptcy Court, including by requesting information from Subordinated Claimants. On March 17, 2021, pursuant to the Securities Claims Procedures, PG&E Corporation and the Utility filed in the Bankruptcy Court certain omnibus objections to certain of the Subordinated Claims. On April 26, 2021, the Bankruptcy Court entered orders disallowing and expunging the Subordinated Claims that were the subject of 2 of the 3 omnibus objections, and certain Subordinated Claims with respect to the third omnibus objection. The remaining Subordinated Claims in the third omnibus objection are subject to additional briefing.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint ~~adds~~added PG&E Corporation and a ~~former~~current officer of PG&E Corporation as defendants, and no longer asserts claims against ~~two~~certain current and former officers of PG&E Corporation previously named in the action. ~~As of April 30, 2020, PG&E Corporation had not yet been served with this complaint.~~

The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing was held on March 11, 2021, where the District Court requested certain supplemental filings, which the parties filed on March 18, 2021. On April 20, 2021, the District Court granted the motion for preliminary approval of the settlement. On April 27, 2021, the parties requested September 7, 2021 for the final fairness and approval hearing. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against ~~the~~certain directors and officers in the securities class ~~action.~~actions and in the litigation matters enumerated above in Note 10 under the heading, “Wildfire-Related Derivative Litigation.” PG&E Corporation and the Utility maintain ~~directors~~directors’ and ~~officers~~officers’ insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the ~~wildfire-related securities class actions~~litigation matters enumerated in Note 10 above under the headings “Wildfire-Related Securities Litigation” and ~~derivative litigation,~~“Wildfire-Related Derivative Litigation,” and are in ~~communication~~arbitration with the carriers regarding, among other things, the applicability of ~~the directors~~multiple years of directors’ and ~~officers~~officers’ insurance policies to those matters. Recovery under the directors’ and officers’ insurance policies in one such litigation matter may impact the directors’ and officers’ insurance proceeds available in the other matters.

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

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

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility ~~has~~ agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and ~~one~~1 count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4). ~~Upon approval and acceptance of the Plea Agreement by~~

On January 15, 2021, the Butte County Superior Court ~~and~~held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust, which was established under the Company’s Plan of Reorganization in Bankruptcy Court and is managed by a trustee and a claims administrator. The Court continued the ~~People have agreed not~~hearing to ~~prosecute any other~~August 20, 2021 for a further update.

Following the 2019 Kincade fire, the Sonoma County District Attorney’s Office opened a criminal ~~charges related to or arising out~~investigation of the ~~2018 Camp fire~~2019 Kincade fire. On April 6, 2021, the Sonoma County District Attorney’s office filed a criminal complaint (the “Complaint”) against the Utility ~~PG&E Corporation or any of their subsidiaries, including PG&E Corporation and the Utility as reorganized pursuant to the Chapter 11 Cases.~~

On March ~~23,~~22, 2021, Cal Fire issued a press release with its determination that the 2020 ~~PG&E Corporation~~Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility ~~filed a motion with~~located north of the ~~Bankruptcy Court seeking authority~~community of Igo. Cal Fire also indicated that its investigative report has been forwarded to ~~enter into~~ the ~~Plea Agreement. On April 16, 2020,~~Shasta County District Attorney’s Office, which is investigating the ~~Bankruptcy Court approved PG&E Corporation’s and the Utility’s Plea Agreement.~~matter. For more information, see “2020 Zogg Fire” above.

Additional investigations and other actions may arise out of the ~~other 2017 Northern California wildfires,~~2019 Kincade fire or the ~~2018 Camp fire, and the 2019 Kincade~~2020 Zogg fire. The timing and outcome for resolution of ~~the referrals by Cal Fire relating to the 2019 Kincade fire to the applicable county District Attorneys’ offices~~any such investigations are uncertain.

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

On July 12, 2019, the California ~~Governor~~governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any ~~calendar~~ year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to ~~Section~~section 3293 of the Public Utilities Code, added by AB 1054.

Electric utility companies that draw from the ~~fund~~Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a ~~rolling three-year~~ disallowance cap equal to 20% of the ~~electric utility company’s~~IOU’s transmission and distribution equity rate base. For the Utility, ~~this~~the disallowance cap ~~is expected to~~would be approximately ~~$2.4~~$2.7 billion ~~for the three-year period starting in 2019,~~based on 2020 equity rate base, and is subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate ~~base.~~base and would apply for a three calendar year period. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the ~~fund,~~Wildfire Fund, resulting in a draw-down of the ~~fund.~~Wildfire Fund.

The Utility is required to attain a safety certification from the CPUC every 12 months, which will be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to section 8389(e) of the Public Utilities Code, added by AB 1054. On January 14, 2021, the WSD approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the safety certification, which the CPUC declined to provide on April 14, 2021.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ~~ratepayers,~~customers, (ii) $7.5 billion in initial contributions from California’s three ~~investor-owned~~large electric ~~utility companies~~IOUs and (iii) $300 million in annual contributions paid by California’s three ~~investor-owned~~large electric ~~utility companies. The~~IOUs for at least a 10 year period. For more information regarding contributions ~~from~~to the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund, ~~allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million).~~ see Note 3 above.

The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. The Wildfire Fund is available to pay for the Utility’s eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. The Wildfire Fund is additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293 of the Public Utilities Code, added by AB 1054.

AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three ~~investor-owned~~large electric ~~utility companies~~IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures ~~will be~~were allocated among the ~~investor-owned electric utility companies~~IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. For more information on the Wildfire Fund allocation metrics, ~~(described above).~~see Note 3 above. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.

~~On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund. On August 7, 2019, PG&E Corporation~~For more information see “Regulatory Recovery” above, Note 3 above and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. On August 26, 2019, the Bankruptcy Court entered an order granting such authorizations. In order to participate in the Wildfire Fund, the Utility must also meet the eligibility and other requirements set forth in AB 1054, and pay its shareNote 14 of the ~~initial contribution~~Notes to the Wildfire Fund upon emergence from Chapter 11. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases.

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.

The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows may be materially affected by the outcome of the following matters.

In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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

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

Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. As a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or ~~will~~planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through March 31, 2021.

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.

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

On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ~~ratepayers~~customers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC ~~could consider and vote on the POD and~~approved the Decision Different ~~as early as~~ on May 7, 2020.

On June 8, 2020, 2 parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as ~~modified by~~modified. On June 23, 2020, the ~~Decision Different, will become effective upon: (i) approval by~~Utility and CUE filed a joint response opposing the applications for rehearing. On December 3, 2020, the CPUC inissued a ~~written~~ decision ~~(ii) following such approval by~~denying the application for rehearing. On January 4, 2021, 1 party filed a petition for review of the CPUC ~~approval~~decision with the California court of the Bankruptcy Court, and (iii) the effectiveness of a chapter 11 plan of reorganization for the Utility approving the implementation of the settlement agreement. The CPUC may accept, reject or propose alternative termsappeals. Responses to the ~~settlement agreement and Decision Different, including imposing additional penalties~~petition were submitted on ~~the Utility.~~

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, ~~and~~ March 1, 2018, and May 1, 2019 for TO18, the TO rate case for 2018 (“TO19”), and ~~TO19,~~the TO rate case for 2019 (“TO20”), respectively. ~~Rates subject to refund for TO20 went into effect on May 1, 2019.~~

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing parties an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020. Initial briefs were filed on December 14, 2020 and reply briefs were filed on February 12, 2021. In addition, the order addresses a number of other issues including: (1) approving depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%; (2) reducing forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period; and (3) upholding the initial decision’s rejection of the Utility’s direct assignment of common plant to transmission and requiring the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. On the direct assignment issue, applying labor ratios to certain common plant would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility ~~expects~~filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021 in the District of Columbia Court of Appeals, and a separate petition for review was jointly filed the same day by two other parties in the Ninth Circuit Court of Appeals. The District of Columbia Court of Appeals and the Ninth Circuit Court of Appeals have issued orders holding the appeals in abeyance until July 14, 2021 and June 30, 2021, respectively, so that the FERC has time to issue a ~~decision in~~substantive order on rehearing. The ultimate outcome on appeal of certain items for which the ~~TO18 rate case in 2020, however,~~Utility requested rehearing could also impact the ~~timing of that decision is uncertain,~~revenues recorded for the TO19 and ~~it will likely be~~TO20 periods. On April 15, 2021, the ~~subject of requests~~FERC issued an order denying the Utility’s request for rehearing and ~~appeal.~~granting the request for rehearing of 2 parties regarding the impact of the Tax Act on TO18 rates in January and February 2018. The Utility may seek rehearing of the FERC’s reversal on the applicability of the Tax Act on TO18 rates which may affect the timing for judicial review of the FERC order on the Utility’s request for rehearing.

As a result of the FERC’s April 15, 2021 order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the first quarter of 2021 by approximately $270 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility has recorded approximately $150 million to Regulatory assets.

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

79On December 30, 2020, the FERC approved an all-party settlement agreement in connection with TO20. The TO20 settlement resolved all issues of the Utility’s formula rate. However, some of the formula rate issues are contingent on the outcome of TO18, including the allocation of costs related to common, general and intangible plant. The settlement provides that the formula rate will remain in effect through December 31, 2023. The Utility is required to make a successor rate filing in 2023 which would go into effect on January 1, 2024.

PG&E Corporation’s net ~~income (loss)~~loss primarily consists of income taxes ~~interest income on cash held,~~and interest expense on long-term ~~debt, and~~debt. PG&E Corporation’s net loss for the three months ended March 31, 2020 also included reorganization items.

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three months ended March 31, ~~2020~~2021 and ~~2019.~~2020. 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 months ended March 31, ~~2020~~2021 and ~~2019,~~2020, 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~~$221 million, or ~~12%~~7%, in the three months ended March 31, ~~2020,~~2021, compared to the same period in ~~2019,~~2020, primarily due to ~~additional~~an increase in base revenues ~~recorded pursuant to~~authorized in the ~~pending TO20~~2020 GRC and 2019 GT&S rate ~~case.~~cases.

The Utility’s operating and maintenance expenses that impacted earnings ~~decreased~~increased by ~~$231~~$245 million or ~~14%,~~17% in the three months ended March 31, ~~2020,~~2021, compared to the same period in ~~2019,~~2020, primarily due to ~~a decrease~~an increase in insurance costs of ~~$198~~approximately $200 million. Additionally, the Utility recognized $79 million ~~related to electric asset inspections costs. Additionally, clean-up~~in previously deferred costs recorded in conjunction with interim rate relief associated with the WMCE application (see “Wildfire Mitigation and ~~repair costs relating to the 2018 Camp fire decreased by $166 million, as compared to the same period in 2019 (the Utility recorded $13 million~~Catastrophic Events Costs Recovery Application” below) in the three months ended March 31, ~~2020 for~~2021, with no comparable costs in the same period in 2020. These increases are partially offset by clean-up and repair costs ~~related to the 2018 Camp fire, as compared to $179 million in same period in 2019). These decreases were partially offset by~~of $43 million ~~for clean-up and repair costs~~ relating to the 2019 Kincade fire incurred in the three months ended March 31, ~~2020.~~

Costs related to wildfires that impacted earnings increased by $172 million, or 100%, in the three months ended March 31, 2021, compared to the same period in 2020. The Utility recognized pre-tax charges of $175 million related to the 2019 Kincade fire and pre-tax charges of $25 million related to the 2020 Zogg fire, offset by $28 million of probable insurance recoveries in the three months ended March 31, 2021, with no comparable costs during the same period in 2020.

Wildfire Fund expense that impacted earnings increased by $119 million, or 100%, in the three months ended March 31, 2021, compared to the same period in 2020. During the quarter ended June 30, 2020, the Utility became eligible to participate in the Wildfire Fund and as a result began to record amortization and accretion expense related to the Wildfire Fund coverage.

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by ~~$58~~$33 million, or 7%4%, in the three months ended March 31, ~~2020,~~2021, compared to the same period in ~~2019,~~2020, primarily due to capital ~~additions and an increase in depreciation rates associated with the 2019 GT&S rate case.~~additions.

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

Interest expense that impacted earnings increased by ~~$151~~$96 million, or ~~150%~~38%, in the three months ended March 31, ~~2020,~~2021, compared to the same period in ~~2019,~~2020 primarily due to the ~~cessation~~issuance of ~~interest accruals on outstanding pre-petition~~new debt ~~in the three months ended March 31, 2019~~ in connection with ~~the~~emergence from 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.~~11.

Other income, net increased by ~~$27~~$40 million, or ~~123%~~82%, in the three months ended March 31, ~~2020,~~2021, compared to the same period in ~~2019, primarily~~2020, due to the decrease in the discount rate resulting in lower expenses on non-service pension ~~expense resulting from higher expected return on plan assets.~~costs.

Reorganization items, net decreased by ~~$18~~$91 million, or ~~16%,~~98% in the three months ended March 31, ~~2020,~~2021, compared to the same period in ~~2019~~2020, primarily due to ~~a $94 million charge recorded in 2019 related to DIP facilities costs, offset by a $72 million increase in expenses directly associated with~~ the Utility’s emergence from Chapter 11 ~~filing.~~

Income tax benefit ~~decreased~~increased by ~~$56~~$53 million ~~or 65%,~~ in the three months ended March 31, ~~2020 as~~2021, compared to the same period 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 in the income tax benefit was~~ primarily ~~the result of higher~~due to lower pre-tax income in ~~the three months ended March 31, 2020,~~2021, compared to the same period in ~~2019.~~2020.

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), fuel and associated transmission ~~fuel~~costs used in its own generation facilities, fuel and associated transmission costs 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.~~incurred. 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.

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

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may increase the cost and availability of short-term borrowings, including credit facilities and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. The collateral posting provisions for some of the Utility’s power and natural gas commodity, and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions. The Utility’s credit ratings fell below investment grade in January 2019, at which time the Utility was required to post additional collateral under its commodity purchase agreements. A further downgrade would not materially impact the collateral postings for procurement activity. (See Notes 8 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.).

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 have been and could continue to be significantly ~~affected.~~affected by the outbreak of COVID-19. 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 for residential and ~~an observed reduction in non-residential electrical load.~~small business customers, as well as for medium and large commercial and industrial customers through June 30, 2021. The ~~reduction in cash collections from customers may be partially offset by reductions in discretionary capital spending or potential regulatory or tax policy changes. As~~Utility’s customer energy accounts receivable balances over 30 days outstanding as of March 31, ~~2020, PG&E Corporation~~2021, were approximately $965 million, or $544 million higher as compared to the balance as of March 31, 2020. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections in 2021 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.for as long as current COVID-19 circumstances persist.

The outbreak of COVID-19 and the resulting economic conditions and government orders have had 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~~submitted 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, which was subsequently updated on June 2, 2020, and July 15, 2020, to modify and clarify the filing based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter. In February and March 2021, the CPUC extended the moratorium on service disconnections to June 30, 2021. In addition, on April 19, 2021, the CPUC issued a final decision to implement a temporary moratorium on service disconnection for medium and large commercial and industrial customers through June 30, 2021. (See “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” below for more information.)

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

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

The ~~commencement~~exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the ~~Chapter 11 Cases constituted~~License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.

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

In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million. SBA paid the Utility $946 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an ~~event~~adjustment for an estimated amount of ~~default or termination event~~payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement through June 30, 2021.

The Utility recorded approximately $365 million of the $946 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $946 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a discounted cash flow model based on business assumptions and ~~caused an automatic and immediate acceleration~~estimates to determine the allocation of the ~~Accelerated Direct Financial Obligations. Accordingly, as a result~~purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are presented within Other non-current liabilities on the Condensed Consolidated Balance Sheets.

The Utility recorded the remaining approximately $475 million ($471 million of which is noncurrent) of the ~~commencement~~sale proceeds to a regulatory liability, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices.

The Utility will amortize the financing obligation through Electric operating revenue and Interest expense on the Condensed Consolidated Statements of Income using the ~~Chapter 11 Cases,~~effective interest method and will amortize the deferred revenue balance through Electric operating revenue ratably over the 100-year term.

In March 2021, the Utility issued $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the ~~Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case~~prepayment of ~~certain indebtedness, premium, if any, thereon, immediately became due and payable. However, any efforts to enforce such payment obligations are automatically stayed as~~all 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$1.5 billion 364-day term loan facility ~~as well as short-term borrowings~~(maturing June 30, 2021) outstanding under ~~PG&E Corporation’s and the Utility’s revolving credit facilities and~~ the Utility’s term loan credit agreement, (ii) the repayment of all of the borrowings outstanding under the revolving credit facility ~~disclosed~~pursuant to the revolving credit agreement and (iii) general corporate purposes.

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”). The Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the Term Loan in an amount equal to $6.875 million on the last day of each quarter.

On February 1, 2021, PG&E Corporation entered into a repricing amendment with the lenders under the Term Loan Agreement pursuant to which, among other things, the applicable margin was reduced from 450 basis points to 300 basis points and the LIBOR floor was reduced from 100 basis points to 50 basis points.

At March 31, 2021, PG&E Corporation and the Utility had $500 million and $2.9 billion available under their respective $500 million and $6.0 billion credit facilities, including the Utility’s term loan credit facility and Receivables Securitization Programs. The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time. As of April 22, 2021, the Receivables Securitization Program had a maximum borrowing base of $888 million and was fully drawn.

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

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. ~~For more information on dividends, see “Dividends”~~

Subject to the dividend restrictions as described in Note 6 of the Notes to the ~~Condensed~~ Consolidated Financial ~~Statements.~~Statements in Item 8 of the 2020 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of March 31, 2021, it is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.

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 months ended March 31, ~~2020,~~2021, net cash provided by operating activities decreased by ~~$662~~$329 million compared to the same period in ~~2019.~~2020. This decrease was ~~due to an increase in vendor payments in 2020 that were not paid during the first quarter of 2019~~primarily due to the ~~automatic stay as~~payment of $758 million to the Fire Victim Trust in accordance with the Plan, and payment for interest in the amount of $467 million, with no similar payments made during the same period in 2020. These payments were partially offset by $581 million of cash received from SBA related to a portion of the ~~Petition Date,~~License Agreement and ~~a reduction in~~Tower Site Agreement, with no similar cash receipts ~~from customers as a result of~~in the ~~economic impacts of~~same period in 2020, and by higher base revenue collections authorized in the ~~COVID-19 pandemic.~~2020 GRC and 2019 GT&S rate cases.

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

Net cash used in investing activities increased by ~~$408~~$141 million during the three months ended March 31, ~~2020~~2021 as compared to the same period in ~~2019.~~2020. 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~~between $7.5 billion and $8.3 billion in capital expenditures in ~~2020.~~2021 and between $7.8 billion and $8.2 billion in 2022. Additionally, future cash flows from investing activities will be impacted by the timing of and amount received from the proposed sale of the Utility’s SFGO.

Net cash provided by financing activities ~~increased~~decreased by ~~$245~~$211 million during the three months ended March 31, ~~2020~~2021 as compared to the same period in 2019. This increase was due to an additional $150 million of borrowings under the DIP Facilities and an approximately $90 million reduction in amounts paid for DIP credit facility debt issuance costs in 2020 as compared to 2019. Additionally, the Utility paid $30 million in bridge facility financing fees in 2020, with no similar amount in 2019.2020.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments. Additionally, future cash flows from financing activities will be affected by the timing and outcome of the Utility’s applications for a post-emergence securitization transaction and for a AB 1054 securitization transaction. (See “Application for Post-Emergence Securitization Transaction” and “Application for AB 1054 Securitization Transaction” below for more information.)

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~~2020 Form ~~10-K and “Part II. Other Information, Item 1. Legal Proceedings.”~~10-K.

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.

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

On December 29, 2020, the court entered an order requiring the Utility to show cause as to why additional proposed conditions of probation should not be added. The proposed conditions would require the Utility to, when determining which distribution lines to de-energize during a PSPS event: (i) take into account the extent to which vegetation bordering those lines is not in compliance with certain requirements, and (ii) to the extent that information shows that such vegetation presents a safety hazard in the event of a windstorm, make a specific determination with respect to that distribution line and de-energize it unless the Utility finds in writing that there are specific reasons to believe that no safety issues exist. The Utility filed its response on January 20, 2021, proposing supplemental language to clarify and specify how the Utility will implement the new conditions proposed by the court. A hearing on the matter was held on February 3, 2021. On February 4, 2021, the court entered an order indicating that, if certain alterations were made, the court may be willing to accept the Utility’s proposed modified conditions in lieu of the conditions proposed in the court’s ~~request,~~December 29, 2020 order. The Utility, the CPUC, the California Governor’s Office of Emergency Services, and amici responded to the order on February 19, 2021. The CPUC and the Utility submitted further responses on March ~~2, 2020,~~19, 2021 and March 22, 2021, respectively, and the CPUC submitted a correction to its March 19, 2021 submission on March 23, 2021. A hearing was held on March 23, 2021. On March 24, 2021, the court issued an order requiring the Utility ~~provided~~to provide, among other information, a revision of the proposed conditions of probation that incorporates consideration of the potential for a tree to fall into an overhead electric line based on its height and distance from the line. The Utility submitted its response on March 29, 2021. On April 20, 2021, the CPUC submitted a letter to the court ~~its target number~~suggesting further revisions to one of ~~contract tree trimmers for 2020, information regarding~~the proposed conditions of probation. On April 21, 2021, the court ordered all parties who wanted to respond to the CPUC’s April 20, 2021 filing to do so by April 26, 2021.

On February 4, 2021, the court entered an order requiring the Utility to show cause as to why the additional proposed conditions of probation suggested by amici in a January 27, 2021 filing should not be added. The proposed conditions would require the Utility to: (i) hire a chief data operations officer with the responsibility to review the Utility’s ~~2019 inspections~~information management and record-keeping systems and manage the relationship to operations, including vegetation management work and PSPS; (ii) initiate steps to prevent data falsification or omission; (iii) propose a plan to mark trees in tier 2 and tier 3 high wildfire danger zones for removal and track the status of ~~Tower 009/081~~the tree removal process for vegetation management; and (iv) propose steps to improve its information management and records-keeping process to improve information integrity, inform analysis, and inform and enhance daily operations including PSPS. The Utility’s and the United States’ responses were submitted on March 3, 2021, and reply by amici was submitted on March 10, 2021.

On April ~~29, 2020,~~20, 2021, the court issued an order ~~imposing new conditions of probation that would require~~requiring the Utility ~~among other things, to:~~to appear on May 4, 2021 in connection with a potential probation violation based on the charges filed by the Sonoma County District Attorney’s office related to the 2019 Kincade fire.

•~~employ, on its own payroll, “a sufficient number~~In the course of ~~inspectors to manage~~2021, the ~~outsourced tree-trimming work,”~~court entered numerous other orders, including ~~pre-inspectors to “identify trees and limbs~~ in violation of California clearance laws that require trimming” and post-inspectors to “spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed,” and submit a detailed plan to carry out this requirement by May 28, 2020;

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

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

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

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

As a result, the Utility is required to submit a corrective action plan to the CPUC’s executive director by May 6, 2021, which is designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. Thereafter, the Utility is required to update the information contained in the corrective action plan every 90 days. The Utility will remain in step 1 of the EOEP until the CPUC determines that the Utility has met the conditions of the corrective action plan. If the Utility does not adequately meet such conditions within the timeframe approved by the CPUC, the CPUC may place the Utility into a higher step of the EOEP, or the Utility may remain in step 1 of the EOEP if it demonstrates sufficient progress towards meeting such conditions.

The Utility is preparing a corrective action plan to address the issues in the draft resolution.

The Utility is unable to predict the outcome of this regulatory process.

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~~2020 Form 10-K.

On ~~February 7,~~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. The Utility’s annual cost of capital adjustment mechanism, which allows for changes in the Utility’s authorized ROE and cost of debt, also remains unchanged. In any year in which the difference between the average Moody’s utility bond rates, as measured in the 12-month period from October through September (the index), and 4.5% (the benchmark) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility must initiate this adjustment mechanism by filing an advice letter on or before October 15, to become effective on January 1 of the next year. The mechanism did not trigger in September 2020; however, as of April 27, 2021, the index was more than 100 basis points below the 4.5% benchmark. If the mechanism triggers in October 2021, then for 2022 the ROE and the cost of debt will be adjusted accordingly. The decision maintains the common equity component of the Utility’s capital structure at 52%, and reduces its preferred stock component from 1% to 0.5%. The decision also approves the cost of debt requested by the Utility.

In accordance with a January 16, 2020 CPUC rate case plan decision, the Utility is required to file with the CPUC on June 30, 2021 a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years. The Utility expects to file the 2023 GRC by June 30, 2021.

On June 30, 2020, the Utility filed the 2020 RAMP Report in advance of its 2023 GRC application. On November 25, 2020, the SPD released its evaluation of the Utility’s 2020 RAMP Report. The SPD found that “[t]he 2020 RAMP showed marked improvements in risk modeling rigor, data quality, and transparency over previous rate cases,” but cautioned that the Utility’s “track record calls for continued improvements by PG&E and continued rigorous oversight by the Commission.” On March 24, 2021, TURN submitted a proposal that would require the Utility to provide an alternative forecast in the 2023 GRC corresponding to the rate of inflation. On April 8, 2021, the Utility submitted a filing opposing TURN’s proposal.

As previously disclosed, in its final decision in the Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount forecast to be recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The audit report was released June 2, 2020 and did not recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit. On July 31, 2020, the Utility filed an ~~interim relief~~ application seeking ~~$899~~recovery of $373.3 million in revenue associated with $512 million of recorded capital expenditures. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony addressing the reasonableness of the capital expenditures. Intervenors’ testimony was served on April 7, 2021 and the Utility’s rebuttal testimony is due on May 5, 2021. The scoping memo calls for the issuance of a PD in the fourth quarter of 2021.

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

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.

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

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

On March 17, 2020, the FERC issued an order denying requests for rehearing previously filed by several parties. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals. Oral argument was held on April 16, 2021. The Utility is unable to predict the timing and outcome of this proceeding.

For ~~additional~~more information, see the 2020 Form 10-K.

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

Also, as previously disclosed, on October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.9%, and an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period, proposed to remove certain items from the Utility’s rate base and revenue requirement, and rejected the Utility’s direct assignment of common plant to transmission and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios.

As previously disclosed, on October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order, among other things, rejects the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopens the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020. Initial briefs and testimony were filed on December 14, 2020 and responses were filed on February 12, 2021.

As previously disclosed, on December 17, 2020, the FERC denied all the pending requests for rehearing that were previously submitted by the Utility and intervenors. On February 11, 2021, the Utility filed a petition for review of the order in the District of Columbia Court of Appeals, and a separate petition for review was jointly filed the same day by two other parties in the Ninth Circuit of Appeals. The District of Columbia Court of Appeals and the Ninth Circuit of Appeals have issued orders holding the appeals in abeyance until July 14, 2021 and June 30, 2021, respectively, so that the FERC has time to issue a substantive order on rehearing. On April 15, 2021, the FERC issued an order denying the Utility’s request for rehearing and granting the request for rehearing of two parties regarding the impact of the Tax Act on TO18 rates in January and February 2018. The Utility may seek rehearing of the FERC’s reversal on the applicability of the Tax Act on TO18 rates which may affect the timing for judicial review of the FERC order on the Utility’s request for rehearing.

As a result of the FERC’s April 15, 2021 order denying rehearing on the common plant allocation, the Utility increased its Regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the first quarter of 2021 by approximately $270 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, the Utility has recorded approximately $150 million to Regulatory assets.

Aside from the ultimate outcome of the common plant allocation, which is subject to further appellate briefing and a further FERC decision on ROE, the FERC’s April 15, 2021 order is not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases. (See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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

For more information, see the 2020 Form 10-K.

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

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

Given the CPUC’s prior approval of $447 million in interim rate relief (which includes interest), the Utility proposed to recover the remaining $868 million revenue requirement, including interest, over a one-year period (following the conclusion of interim rate relief recovery). Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief of $447 million being subject to refund.

Intervenors’ testimony was served on April 14, 2021 and the Utility’s rebuttal testimony is due on April 30, 2021. The scoping memo and ruling for the proceeding calls for a PD to be issued in September 2021.

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

For more information regarding the FHPMA, the FRMMA, the WMPMA, and the CEMA memorandum accounts, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and the 2020 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.~~

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.

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

~~In accordance with a January 16, 2020 CPUC decision~~For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan the decision, the Utility is required to file with the CPUC on June 30, 2021 a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.Item 1.

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. In the 2020 GRC Decision, the CPUC required the Utility to track these costs in the VMBA beginning January 1, 2020. The Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

The ~~Resolution~~resolution also authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the ~~Resolution.~~resolution. On February 11, 2021, the CPUC approved a resolution extending the moratorium on service disconnections for residential and small business customers to June 30, 2021. In addition, the February 11, 2021 resolution ordered the utilities to file advice letters containing their respective transition plans associated with the discontinuance of the emergency customer protections on June 30, 2021. The Utility filed its advice letter and transition plan to the CPUC for review on April 1, 2021, which was approved by the CPUC on April 28, 2021.

On June 11, 2020, the CPUC issued a final decision as part of the OIR to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs that permanently eliminated deposit requirements for residential customers. On April 19, 2021, the CPUC issued a final decision to implement a temporary moratorium on service disconnection for medium and large commercial and industrial customers through June 30, 2021. To be eligible, medium or large commercial or industrial customers must be enrolled in and current on a payment plan by June 30, 2021. The final decision authorized the Utility to submit an advice letter to establish a memorandum account to track incremental costs for the period of December 30, 2020 to June 30, 2021 for this moratorium. The Utility expects to submit the advice letter by May 14, 2021.

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

For more information, see the 2020 Form 10-K.

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

The Utility proposes the SFGO sale and headquarters transition proceed in several interrelated steps: the Utility has entered into a lease for the Lakeside Building with an option to purchase the Lakeside Building; the Utility will market and sell the SFGO, subject to CPUC approval; and the Utility will enter into an agreement with the buyer of the SFGO to lease back space during the multi-year relocation period (collectively, the “Transactions”). As space in the Lakeside Building becomes available following the expiration of existing tenants’ leases and completion of the redevelopment of the property to the Utility’s specifications, the Utility will relocate employees and operations from the SFGO and certain East Bay office locations to the Lakeside Building in phases over several years, beginning in 2022.

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

On December 15, 2020, the assigned commissioner issued a scoping memo, which contemplates a CPUC final decision as early as August 2021 and provides for additional timeline flexibility depending on the pace of the sale process. On April 21, 2021, the Utility entered into a settlement agreement with certain other parties and submitted the settlement agreement to the CPUC for approval. Under the settlement, the parties agree that (1) the Utility’s headquarters strategy, including the move to Oakland, the sale of SFGO, and the terms of the agreement to lease and the option to purchase the Lakeside Building, is reasonable, (2) all of the gain on sale of SFGO will be returned to customers over five years, beginning in 2022, and (3) the SFGO sale terms and the costs associated with the Utility’s move to the Lakeside Building and development will be considered at later stages of the proceeding and through the CPUC’s advice letter process.

The Utility launched the marketing of the SFGO in March 2021.

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

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to ~~securitize~~recover $7.5 billion of 2017 wildfire claims costs through securitization 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. AsAmong other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of ~~temporary~~ Utility debt and accelerate a ~~$700~~$592 million payment due to the Fire Victim ~~Trust post-Effective Date.~~Trust. Specifically, the application requests administration of the ~~Stress Test Methodology~~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~~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~~proposes a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds. The Utility ~~proposes~~initially proposed 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~~proposed to share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

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

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

On January 6, 2021, the Utility filed an application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to securitize the $7.5 billion of claims associated with the 2017 Northern California Wildfires referenced above. On January 7, 2021, the Utility filed a motion to consolidate the pending application seeking authorization for a post-emergence transaction and the application for a financing order. The ALJ granted the Utility’s motion to shorten the time for protests to January 22, 2021, and the Utility filed a reply on February 1, 2021. A prehearing conference was held on February 5, 2021. On February 10, 2021, certain intervenors filed a joint motion to dismiss the Utility’s application for a financing order. On February 17, 2021, the Utility filed a response opposing the motion to dismiss. Also on February 17, 2021, the PAO filed a response supporting the motion to dismiss. Opening briefs were submitted on March 1, 2021, and reply briefs were submitted on March 12, 2021.

~~For~~On March 23, 2021, the ALJ issued a PD granting the Utility’s application for a post-emergence transaction to securitize $7.5 billion. On April 5, 2021, the ALJ issued a PD granting the Utility’s application for a financing order authorizing the issuance of recovery bonds in connection with the post-emergence transaction. Oral argument on both applications was held before the CPUC on April 9, 2021. The parties filed opening comments on the PD granting the Utility’s application for a post-emergence transaction to securitize $7.5 billion on April 12, 2021, and reply comments on April 19, 2021. On April 21, 2021, a revised PD was issued. On April 23, 2021, the CPUC issued a decision granting the Utility’s application for a post-emergence transaction to securitize $7.5 billion. The parties filed opening comments on the PD granting the Utility’s application for a financing order on April 26, 2021, and reply comments are due on May 3, 2021. The Utility expects a CPUC decision on the financing order by May 6, 2021.

On February 24, 2021 the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to $1.19 billion of fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021.  The $1.19 billion reflects capital expenditures related to the Utility’s Community Wildfire Safety Program that were approved by the CPUC in the 2020 GRC, and includes $655 million in recorded 2020 capital expenditures and an additional ~~information, see~~$535 million in forecast capital expenditures in 2021.  The final amount to be securitized would be based on recorded 2020 and 2021 Community Wildfire Safety Program capital expenditures incurred by the ~~2019 Form 10-K.~~Utility prior to the securitization transaction.

The application requests that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest and would reduce rates on a present value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a NBC sufficient to pay debt service on the recovery bonds.  The application also requests to exclude the securitized debt from the Utility’s ratemaking capital structure and to adjust its 2020 GRC revenue requirement following the issuance of the recovery bonds.  The application indicates that the issuance of the bonds is anticipated to occur before the end of 2021, but timing is subject to change.

On March 30, 2021, the CPUC held a prehearing conference. The assigned commissioner issued the scoping memo on April 5, 2021. The parties filed opening briefs on April 23, 2021, and reply briefs are due on May 7, 2021. The Utility expects a CPUC decision on the financing order by June 24, 2021.

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

On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved the Utility’s 2020 WMP. The resolutions indicate that while the Utility’s 2020 WMP met the minimum requirements for its submission, the deficiencies found, classified as severity level A, B, or C Conditions, require significant follow-up from the Utility and oversight to ensure appropriate remedies for the deficiencies. The Utility received 41 Conditions in total with the first set, classified as Class A Conditions, submitted on July 27, 2020. The second set, Class B Conditions, were completed on September 9, 2020 and the third, Class C Conditions, were submitted as part of the 2021 WMP update on February 5, 2021. On December 30, 2020, the WSD issued a Notice of Non-Compliance finding that the Utility’s responses to the Class A Conditions were insufficient. The WSD has required the Utility to include 39 action items in its 2021 WMP to address the insufficient responses. On January 8, 2021, the WSD issued a Notice of Non-Compliance finding that the Utility’s quarterly report addressing the Class B Conditions was insufficient. The WSD directed the Utility to respond to 84 action items in its 2021 WMP or via a supplemental filing by February 26, 2021. The Utility’s 2021 WMP was submitted on February 5, 2021. The 2021 WMP updated the 2020 WMP and addressed the Utility’s wildfire safety programs focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread and reducing the impact of PSPS events. On February 26, 2021, the Utility submitted its supplemental filing addressing the remaining action items regarding the Class A and Class B conditions that WSD determined were insufficient.

Failure to remedy insufficiencies in the 2020-2022 WMP could lead to enforcement actions by the CPUC, including potentially placing the Utility in the EOEP, and making the Utility unable to obtain an AB 1054 safety certification and, as a result, unable to access the Wildfire Fund, which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

On March ~~18, 2020,~~4, 2021, the Utility notified the CPUC ~~issued~~it had missed inspections for a ~~decision~~small percentage of assets in ~~this proceeding, clarifying~~HFTD areas that were subject to the ~~CPUC’s newly created Wildfire Safety Division will review~~ 2020 ~~wildfire mitigation plans, present resolutions for~~WMP. On March 12, 2021, the Utility submitted a report updating the CPUC ~~consideration~~ on the ~~2020 Plans, and oversee independent evaluation and other compliance activity with regard~~Utility’s progress in completing the missing inspections. The Utility is undertaking a review of its electric asset inspections. For more information, see “Electric Asset Inspections” below.

On April 27, 2021, the WSD extended its deadline to ~~both 2019 and 2020 Plans.~~issue a determination on the Utility’s 2021 WMP. The Utility expects the WSD to require modification of the WMP through the issuance of revision notices, which the CPUC is expected to send by May 5, 2021. The Utility will then have 30 days to respond to a revision notice. The Utility is unable to predict the timing or outcome of a CPUC decision on the 2021 WMP.

~~Also, as previously disclosed, PG&E Corporation and the Utility expect the CPUC to issue a decision on its 2020-2022 WMP by June 2020.~~ PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 ~~Wildfire Mitigation Plan,~~WMP, 2020 WMP, and ~~the 2020-2022 Wildfire Mitigation Plan~~2021 WMP recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.

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~~spring or ~~Summer~~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~~

The CPUC adopted a decision in the first track of the proceeding on June 11, 2020 (the “Track 1 2020, the Utility filed a motion seeking to supplement its original proposal and to reduce the total cost recovery authorization it is 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 and that the Utility had suspended its solicitation for permanent generation located at substationsDecision”), which approved with online dates in 2020. The Utility’s supplemental testimony also attached contracts the Utility had executed with mobile generation vendors for over 300 megawatts of capacity for use in 2020. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying on procedural grounds the Utility’s motion to supplement its proposal. On April 29, 2020, the CPUC issued a proposed decision that would conditionally approveconditions the Utility’s proposal and ~~would allow~~requires the Utility to track costs in a new memorandum account for subsequent regulatory review and recovery in rates.

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

On March 5, 2021, the Utility submitted an advice letter seeking authorization to track and record costs for the reservation and operation of up to 168 MW of temporary generation to support substation-level microgrids during 2021 PSPS events. The CPUC approved that advice letter in part on April 14, 2021, specifically approving the request to reserve up to 168 MW of temporary generation in 2021. The CPUC’s disposition letter does not address or resolve the Utility’s plan to establish any clean substation project(s) in 2021, stating that it will address that issue separately.

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.

On ~~January 22,~~June 30, 2020, the Utility entered into 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.~~

•~~Enhanced Enforcement Process:~~ ~~adopts an Enhanced Oversight~~The Utility is unable to predict the timing and ~~Enforcement Process for the Utility;~~

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of ~~a non-bypassable charge~~an NBC to support the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision finding that the imposition of the ~~non-bypassable charge~~NBC is just and reasonable. In addition, the decision affirmed that the Utility and its customers will not pay an allocated share of the adopted wildfire charge revenue requirement unless and until the Utility participates in the Wildfire Fund. The decision also continues the same allocation of the wildfire charge revenue requirement among the ~~investor-owned utilities~~IOUs as previously adopted for the Department of Water Resources power and bond charge revenue requirements. The decision ~~proposes~~adopts revenue requirements for the Utility of $404.6 million, which is based on average annual collections and ~~shall~~will 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,December 17, 2020, the CPUC ~~issued a decision denying~~authorized the ~~application for rehearing.~~Utility to collect the Wildfire Fund NBC from eligible customers from January 1, 2021 through December 31, 2021 in the amount of $0.00580 per kilowatt-hour. On December 30, 2020, the Utility submitted an advice letter incorporating final rates effective January 1, 2021.

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

OnAs previously disclosed, 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~~On February 26, 2021, the ALJ issued a ruling seeking comments regarding penalties and financial incentives and potential mechanisms for implementation. Other questions included whether the CPUC should establish new rules to attempt to decrease the risk of electricity price volatility caused by potential gas supply issues and if certain pipeline operating procedures should be uniform across the state. Parties filed ~~opening~~ comments on the ~~preliminary scope on February 26, 2020 and reply comments~~questions 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~~19, 2021. In accordance with the amended procedural schedule, 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 for July 2020.

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,~~May 28, 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,~~On December 2, 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~~parties submitted comments in ~~place for as long as~~this proceeding in response to an August 3, 2020 scoping ruling regarding SED’s report in a ~~State of Emergency or shelter-in-place order remains in effect due~~separate PSPS-related proceeding, OII to Examine the ~~COVID-19 pandemic. The~~Late 2019 Public Safety Power Shutoff Events. In their comments, the Utility and other ~~entities (including other IOUs) filed responses on April 20, 2020, requesting~~parties commented that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. The CPUC’s April 27, 2020, proposed decision did not act on this motion. PG&E Corporation and the Utility are unable to predict the timing and the outcomeissues raised in SED’s report should be addressed in a Phase 3 of this ~~request.~~

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, October 23-25, 2019, and October ~~23-November~~26-November 1, 2019.

~~The~~Opening briefs were filed on October 30, 2020 by all parties, which included an intervenor proposing financial penalties against the Utility ~~filed its testimony with~~of $166 million. If adopted by the CPUC, such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Reply briefs were filed by all parties on November 17, 2020, including the Utility, which opposed the imposition of any penalties.

On February ~~5, 2020.~~19, 2021, the CPUC issued a scoping memo proposing updated or additional new guidelines in Phase 3 of this proceeding. If adopted, these guidelines would require utilities to submit annual pre- and post- season reports, have certain percentages of Community Resource Centers be indoors, conduct public outreach in all languages prevalent in its service territory, have a webpage that explains “critical facility” requirements, implement new notification requirements and conduct de-energization simulation exercises. Parties ~~filed testimony on February 28, 2020; concurrent rebuttal was filed on April 7, 2020;~~commented in March 2021, and ~~hearings have been suspended indefinitely pending the COVID-19-related restrictions.~~a PD is expected in May 2021, with a final decision in June 2021.

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


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~~SHAREHOLDERS ’ 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
			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 6. EXHIBITS
			SIGNATURES


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”
2020 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, 2020
AB			Assembly ~~Bill~~bill
AFUDC			allowance for funds used during construction
ALJ			~~administrative law judge~~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~~customer harm threshold
Confirmation Order			the order confirming PG&E Corporation’s and the Utility’s and the Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization, dated as of June 20, 2020 with the Bankruptcy Court
CPE			central procurement entities
CPPMA			COVID-19 Pandemic Protections Memorandum Account
CPUC			California Public Utilities Commission
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
Effective Date			July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EMANI			European Mutual Association for Nuclear Insurance
EOEP			Enhanced Oversight and Enforcement Process
EPS			earnings per common share
Exchange Act			Securities Exchange Act of 1934, as amended
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) ishas been, and will continue to be funded
Formula Rate Proceedings			consolidated proceedings for the TO18 and TO20 rate cases
FRMMA			Fire Risk Mitigation Memorandum Account
GAAP			U.S. Generally Accepted Accounting Principles
GRC			general rate case
GT&S			gas transmission and storage
~~HSM~~HFTD			~~Hazardous Substance Memorandum Account~~
~~IOU(s)~~			~~investor-owned utility(ies)~~
~~LIBOR~~			~~London Interbank Offered Rate~~
~~LSTC~~			~~liabilities subject to compromise~~High Fire-Threat District


HSM			Hazardous Substance Memorandum Account
IOU(s)			investor-owned utility(ies)
IRS			Internal Revenue Service
Lakeside Building			300 Lakeside Drive, Oakland, California, 94612
LSE			load serving entity
MW			1 Megawatt (MW) = One thousand kilowatts
MWh			1 Megawatt-Hour (MWh) = One megawatt continuously for one hour
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~~NBC			~~Nuclear Decommissioning Cost Triennial Proceedings~~non-bypassable charge
NEIL			Nuclear Electric Insurance Limited
NEM			net energy metering
NRC			Nuclear Regulatory Commission
~~OES~~			~~State of California Office of Emergency Services~~
OII			order instituting investigation
OIR			order instituting rulemaking
OSA			Office of the Safety Advocate, a division of the CPUC
PCIA			Power Charge Indifference Adjustment
PERA			Public Employees Retirement Association of New Mexico
POD			Presiding Officer’s Decision
PD			proposed decision
Petition Date			January 29, 2019
~~PFM~~the Plan			~~petition for modification~~
~~PSA~~			~~plan support agreement~~Debtors’ and Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization, dated June 19, 2020
PSPS			Public Safety Power Shutoff
RA			resource adequacy
RAMP			Risk Assessment Mitigation Phase Report
ROE			return on equity
RSA			restructuring support agreement (as amended)
RTBA			Risk Transfer Balancing Account
SB			Senate Bill
SEC			U.S. Securities and Exchange Commission
Securities Act			The Securities Act of 1933, as amended
SED			Safety and Enforcement Division of the CPUC
SPD			CPUC’s Safety Policy Division
SPV			PG&E AR Facility, LLC
Subrogation RSA			Restructuring Support Agreement dated September 22, 2019 with certain holders of insurance subrogation claims, as amended
Tax Act			Tax Cuts and Jobs Act of 2017
TCC			Official Committee of Tort Claimants
TCC RSA			Restructuring Support Agreement dated December 6, 2019 with the TCC and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended
TO			transmission owner
TURN			The Utility Reform Network
Utility			Pacific Gas and Electric Company
VIE(s)			variable interest entity(ies)


		(Unaudited)							(Unaudited)
		Three Months Ended March 31,							Three Months Ended March 31,
(in millions, except per share amounts)	(in millions, except per share amounts)	2020		2019		(in millions, except per share amounts)	2021		2020
Operating Revenues	Operating Revenues					Operating Revenues
Electric	Electric	$	3,040	$	2,792	Electric	$	3,395	$	3,040
Natural gas	Natural gas	1,266		1,219		Natural gas	1,321		1,266
Total operating revenues	Total operating revenues	4,306		4,011		Total operating revenues	4,716		4,306
Operating Expenses	Operating Expenses					Operating Expenses
Cost of electricity	Cost of electricity	545		599		Cost of electricity	590		545
Cost of natural gas	Cost of natural gas	284		339		Cost of natural gas	307		284
Operating and maintenance	Operating and maintenance	1,967		2,087		Operating and maintenance	2,336		1,967
Wildfire-related claims, net of insurance recoveries						Wildfire-related claims, net of insurance recoveries	172		0
Wildfire Fund expense						Wildfire Fund expense	119		0
Depreciation, amortization, and decommissioning	Depreciation, amortization, and decommissioning	855		797		Depreciation, amortization, and decommissioning	888		855
Total operating expenses	Total operating expenses	3,651		3,822		Total operating expenses	4,412		3,651
Operating Income	Operating Income	655		189		Operating Income	304		655
Interest income	Interest income	16		22		Interest income	2		16
Interest expense	Interest expense	(254)		(103)		Interest expense	(408)		(254)
Other income, net	Other income, net	97		71		Other income, net	127		97
Reorganization items, net	Reorganization items, net	(176)		(127)		Reorganization items, net	0		(176)
Income Before Income Taxes	Income Before Income Taxes	338		52		Income Before Income Taxes	25		338
Income tax benefit	Income tax benefit	(36)		(84)		Income tax benefit	(98)		(36)
Net Income	Net Income	374		136		Net Income	123		374
Preferred stock dividend requirement of subsidiary	Preferred stock dividend requirement of subsidiary	3		—		Preferred stock dividend requirement of subsidiary	3		3
Income Available for Common Shareholders	Income Available for Common Shareholders	$	371	$	136	Income Available for Common Shareholders	$	120	$	371
Weighted Average Common Shares Outstanding, Basic	Weighted Average Common Shares Outstanding, Basic	529		526		Weighted Average Common Shares Outstanding, Basic	1,985		529
Weighted Average Common Shares Outstanding, Diluted	Weighted Average Common Shares Outstanding, Diluted	648		527		Weighted Average Common Shares Outstanding, Diluted	2,131		648
Net Income Per Common Share, Basic		$	0.70	$	0.25
Net Income Per Common Share, Diluted		$	0.57	$	0.25
Net Earnings Per Common Share, Basic						Net Earnings Per Common Share, Basic	$	0.06	$	0.70
Net Earnings Per Common Share, Diluted						Net Earnings Per Common Share, Diluted	$	0.06	$	0.57

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)							(Unaudited)
		Three Months Ended March 31,							Three Months Ended March 31,
(in millions)	(in millions)	2020		2019		(in millions)	2021		2020
Net Income	Net Income	$	374	$	136	Net Income	$	123	$	374
Other Comprehensive Income	Other Comprehensive Income					Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)	Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)	—		—		Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)	1		0
Total other comprehensive income	Total other comprehensive income	—		—		Total other comprehensive income	1		0
Comprehensive Income	Comprehensive Income	374		136		Comprehensive Income	124		374
Preferred stock dividend requirement of subsidiary	Preferred stock dividend requirement of subsidiary	3		—		Preferred stock dividend requirement of subsidiary	3		3
Comprehensive Income Available for Common Shareholders	Comprehensive Income Available for Common Shareholders	$	371	$	136	Comprehensive Income Available for Common Shareholders	$	121	$	371

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.


VMBA			Vegetation Management Balancing Account
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
WMBA			Wildfire Mitigation Balancing Account
WMCE			Wildfire Mitigation and Catastrophic Events
WMP			Wildfire Mitigation Plan
WMPMA			Wildfire Mitigation Plan Memorandum Account
WSD			Wildfire Safety Division


		(Unaudited)							(Unaudited)
		Balance At							Balance At
(in millions)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	March 31, 2021		December 31, 2020
ASSETS	ASSETS					ASSETS
Current Assets	Current Assets					Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	1,960	$	1,570	Cash and cash equivalents	$	229	$	484
Restricted cash						Restricted cash	29		143
Accounts receivable:	Accounts receivable:					Accounts receivable:
Customers (net of allowance for doubtful accounts of $46 and $43 at respective dates)		1,319		1,287
Accrued unbilled revenue		946		969
Customers (net of allowance for doubtful accounts of $212 million and $146 million at respective dates) (includes $1.61 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $211 million and $143 million at respective dates)						Customers (net of allowance for doubtful accounts of $212 million and $146 million at respective dates) (includes $1.61 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $211 million and $143 million at respective dates)	1,835		1,883
Accrued unbilled revenue (includes $897 million and $959 million related to VIEs at respective dates)						Accrued unbilled revenue (includes $897 million and $959 million related to VIEs at respective dates)	991		1,083
Regulatory balancing accounts	Regulatory balancing accounts	2,102		2,114		Regulatory balancing accounts	2,249		2,001
Other	Other	2,613		2,617		Other	1,157		1,172
Regulatory assets	Regulatory assets	373		315		Regulatory assets	410		410
Inventories:	Inventories:					Inventories:
Gas stored underground and fuel oil	Gas stored underground and fuel oil	77		97		Gas stored underground and fuel oil	17		95
Materials and supplies	Materials and supplies	567		550		Materials and supplies	533		533
Wildfire Fund asset						Wildfire Fund asset	464		464
Other	Other	601		646		Other	1,153		1,334
Total current assets	Total current assets	10,558		10,165		Total current assets	9,067		9,602
Property, Plant, and Equipment	Property, Plant, and Equipment					Property, Plant, and Equipment
Electric	Electric	63,750		62,707		Electric	68,054		66,982
Gas	Gas	23,045		22,688		Gas	24,548		24,135
Construction work in progress	Construction work in progress	2,670		2,675		Construction work in progress	2,895		2,757
Other	Other	20		20		Other	25		20
Total property, plant, and equipment	Total property, plant, and equipment	89,485		88,090		Total property, plant, and equipment	95,522		93,894
Accumulated depreciation	Accumulated depreciation	(26,987)		(26,455)		Accumulated depreciation	(28,261)		(27,758)
Net property, plant, and equipment	Net property, plant, and equipment	62,498		61,635		Net property, plant, and equipment	67,261		66,136
Other Noncurrent Assets	Other Noncurrent Assets					Other Noncurrent Assets
Regulatory assets	Regulatory assets	6,604		6,066		Regulatory assets	9,159		8,978
Nuclear decommissioning trusts	Nuclear decommissioning trusts	2,911		3,173		Nuclear decommissioning trusts	3,592		3,538
Operating lease right of use asset	Operating lease right of use asset	2,209		2,286		Operating lease right of use asset	1,659		1,741
Wildfire Fund asset						Wildfire Fund asset	5,700		5,816
Income taxes receivable	Income taxes receivable	67		67		Income taxes receivable	68		67
Other	Other	1,841		1,804		Other	2,052		1,978
Total other noncurrent assets	Total other noncurrent assets	13,632		13,396		Total other noncurrent assets	22,230		22,118
TOTAL ASSETS	TOTAL ASSETS	$	86,688	$	85,196	TOTAL ASSETS	$	98,558	$	97,856

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.


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	—	$	(10)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	326	$	242
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		529,236,741	$	13,038	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388
Balance at December 31, 2020															Balance at December 31, 2020	1,984,678,673	$	30,224	$	(9,196)	$	(27)	$	21,001	$	252	$	21,253
Net income	Net income	—	—		374		—		374		—		374		Net income	—	—		123		—		123		—		123
Other comprehensive loss		—	—		—		—		—		—		—
Other comprehensive income															Other comprehensive income	—	—		—		1		1		—		1
Common stock issued, net	Common stock issued, net	549,155	—		—		—		—		—		—		Common stock issued, net	427,030	0		—		—		0		—		0
Stock-based compensation amortization	Stock-based compensation amortization	—	(3)		—		—		(3)		—		(3)		Stock-based compensation amortization	—	2		—		—		2		—		2
Balance at March 31, 2020		529,785,896	$	13,035	$	(7,518)	$	(10)	$	5,507	$	252	$	5,759
Balance at March 31, 2021															Balance at March 31, 2021	1,985,105,703	$	30,226	$	(9,073)	$	(26)	$	21,127	$	252	$	21,379


(in millions)	(in millions)	Preferred Stock		Common Stock Amount		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity		(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
Balance at December 31, 2020														Balance at December 31, 2020	$	258	$	1,322	$	28,286	$	(4,385)	$	(5)	$	25,476
Net income	Net income	—		—		—		451		—		451		Net income	—		—		—		177		—		177
Balance at March 31, 2020		$	258	$	1,322	$	8,550	$	(4,345)	$	1	$	5,786
Balance at March 31, 2021														Balance at March 31, 2021	$	258	$	1,322	$	28,286	$	(4,208)	$	(5)	$	25,653


(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Financing debt⁽²⁾	$	22,627	$	671	$	23,298
Wildfire-related claims⁽³⁾	25,548		—		25,548
Trade creditors	1,200		5		1,205
Non-qualified benefit plan	20		132		152
2001 bankruptcy disputed claims ⁽⁴⁾	238		—		238
Customer deposits & advances	78		—		78
Other	230		2		232
Total Liabilities Subject to Compromise	$	49,941	$	810	$	50,751


	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 March 31, 2021
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	0	$	0	$	0
Legal and other	5		(2)		3
Other	(3)		0		(3)
Total reorganization items, net	$	2	$	(2)	$	0


		Pension Benefits						Other Benefits							Pension Benefits				Other Benefits
		Three Months Ended March 31,															Three Months Ended March 31,
(in millions)	(in millions)	2020		2019		2020		2019		(in millions)	2021		2020		2021		2020
Service cost for benefits earned⁽¹⁾	Service cost for benefits earned⁽¹⁾	$	132	$	111	$	15	$	14	Service cost for benefits earned (1)	$	147	$	132	$	16	$	15
Interest cost	Interest cost	178		189		16		19		Interest cost	161		178		13		16
Expected return on plan assets	Expected return on plan assets	(261)		(227)		(34)		(31)		Expected return on plan assets	(261)		(261)		(35)		(34)
Amortization of prior service cost	Amortization of prior service cost	(1)		(1)		3		4		Amortization of prior service cost	(1)		(1)		4		3
Amortization of net actuarial loss	Amortization of net actuarial loss	1		1		(5)		(1)		Amortization of net actuarial loss	1		1		(8)		(5)
Net periodic benefit cost	Net periodic benefit cost	49		73		(5)		5		Net periodic benefit cost	47		49		(10)		(5)
Regulatory account transfer⁽²⁾	Regulatory account transfer⁽²⁾	34		10		—		—		Regulatory account transfer (2)	37		34		0		0
Total	Total	$	83	$	83	$	(5)	$	5	Total	$	84	$	83	$	(10)	$	(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 March 31, 2021
Beginning balance	Beginning balance	$	(22)	$	17	$	(5)	Beginning balance	$	(39)	$	17		$	(22)
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)	Amortization of prior service cost (net of taxes of $0 and $1, respectively)	(1)		2		1		Amortization of prior service cost (net of taxes of $0 and $1, respectively)	(1)		3			2
Amortization of net actuarial loss (net of taxes of $0 and $2, respectively)	Amortization of net actuarial loss (net of taxes of $0 and $2, respectively)	1		(3)		(2)		Amortization of net actuarial loss (net of taxes of $0 and $2, respectively)	1		(6)			(5)
Regulatory account transfer (net of taxes of $0 and $1, respectively)	Regulatory account transfer (net of taxes of $0 and $1, respectively)	—		1		1		Regulatory account transfer (net of taxes of $0 and $1, respectively)	1		3			4
Net current period other comprehensive gain (loss)	Net current period other comprehensive gain (loss)	—		—		—		Net current period other comprehensive gain (loss)	1		0			1
Ending balance	Ending balance	$	(22)	$	17	$	(5)	Ending balance	$	(38)	$	17		$	(21)


		Receivable Balance at							Receivable Balance at
(in millions)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	March 31, 2021		December 31, 2020
Electric distribution	Electric distribution	$	213	$	—	Electric distribution	$	266	$	0
Electric transmission		—		9
Gas distribution and transmission	Gas distribution and transmission	45		363		Gas distribution and transmission	3		102
Energy procurement	Energy procurement	881		901		Energy procurement	346		413
Public purpose programs	Public purpose programs	288		209		Public purpose programs	309		292
Fire hazard prevention memorandum account						Fire hazard prevention memorandum account	121		121
Fire risk mitigation memorandum account						Fire risk mitigation memorandum account	33		33
Wildfire mitigation plan memorandum account						Wildfire mitigation plan memorandum account	161		161
Wildfire mitigation balancing account						Wildfire mitigation balancing account	29		27
General rate case memorandum accounts						General rate case memorandum accounts	468		313
Vegetation management balancing account						Vegetation management balancing account	49		115
Insurance premium costs						Insurance premium costs	157		135
Other	Other	675		632		Other	307		289
Total regulatory balancing accounts receivable	Total regulatory balancing accounts receivable	$	2,102	$	2,114	Total regulatory balancing accounts receivable	$	2,249	$	2,001


		Payable Balance at							Payable Balance at
(in millions)	(in millions)	March 31, 2020		December 31, 2019		(in millions)	March 31, 2021		December 31, 2020
Electric distribution	Electric distribution	$	—	$	31	Electric distribution	$	0	$	55
Electric transmission	Electric transmission	148		119		Electric transmission	260		267
Gas distribution and transmission	Gas distribution and transmission	74		45		Gas distribution and transmission	280		76
Energy procurement	Energy procurement	585		649		Energy procurement	116		158
Public purpose programs	Public purpose programs	565		559		Public purpose programs	372		410
Other	Other	473		394		Other	340		279
Total regulatory balancing accounts payable	Total regulatory balancing accounts payable	$	1,845	$	1,797	Total regulatory balancing accounts payable	$	1,368	$	1,245


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


(in millions)	Termination Date	Facility Limit			Borrowings Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	July 2023	$	3,500	(1)	$	0	$	979	$	2,521
Utility term loan credit facility (2)	January 2022	1,500			1,500		0		0
Utility receivables securitization program (3)	October 2022	1,000		(4)	650		0		350		(4)
PG&E Corporation revolving credit facility	July 2023	500			0		0		500
Total credit facilities		$	6,500		$	2,150	$	979	$	3,371


		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


			Contract Volume at					Contract Volume at
Underlying Product	Underlying Product	Instruments	March 31, 2020	December 31, 2019	Underlying Product	Instruments	March 31, 2021	December 31, 2020
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	219,348,075	146,642,863
		Options	7,760,000	14,720,000		Options	17,080,000	14,140,000
Electricity (Megawatt-hours)		Forwards, Futures and Swaps	49,291,087	18,675,852
Electricity (MWh)					Electricity (MWh)	Forwards, Futures and Swaps	11,127,600	9,435,830
		Options	4,414,400	—		Options	588,800	0
		Congestion Revenue Rights ⁽³⁾	298,648,904	308,467,999		Congestion Revenue Rights (3)	264,206,953	266,091,470


	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	50	$	(3)	$	105	$	152
Noncurrent assets – other	136		0		0		136
Current liabilities – other	(41)		3		17		(21)
Noncurrent liabilities – other	(228)		0		3		(225)
Total commodity risk	$	(83)	$	0	$	125	$	42


		Fair Value Measurements																			Fair Value Measurements
		March 31, 2020																			March 31, 2021
(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	$	228	$	0	$	0	$	—	$	228
Nuclear decommissioning trusts	Nuclear decommissioning trusts											Nuclear decommissioning trusts
Short-term investments	Short-term investments	82		—		—		—		82		Short-term investments	29		0		0		—		29
Global equity securities	Global equity securities	1,792		—		—		—		1,792		Global equity securities	2,461		0		0		—		2,461
Fixed-income securities	Fixed-income securities	784		734		—		—		1,518		Fixed-income securities	953		812		0		—		1,765
Assets measured at NAV	Assets measured at NAV	—		—		—		—		17		Assets measured at NAV	—		—		—		—		27
Total nuclear decommissioning trusts ⁽²⁾	Total nuclear decommissioning trusts ⁽²⁾	2,658		734		—		—		3,409		Total nuclear decommissioning trusts (2)	3,443		812		0		—		4,282
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	0		17		165		1		183
Gas	Gas	—		2		—		—		2		Gas	0		4		0		101		105
Total price risk management instruments	Total price risk management instruments	—		9		159		5		173		Total price risk management instruments	0		21		165		102		288
Rabbi trusts	Rabbi trusts											Rabbi trusts
Fixed-income securities	Fixed-income securities	—		102		—		—		102		Fixed-income securities	0		102		0		—		102
Life insurance contracts	Life insurance contracts	—		76		—		—		76		Life insurance contracts	0		76		0		—		76
Total rabbi trusts	Total rabbi trusts	—		178		—		—		178		Total rabbi trusts	0		178		0		—		178
Long-term disability trust	Long-term disability trust											Long-term disability trust
Short-term investments	Short-term investments	6		—		—		—		6		Short-term investments	5		0		0		—		5
Assets measured at NAV	Assets measured at NAV	—		—		—		—		157		Assets measured at NAV	—		—		—		—		158
Total long-term disability trust	Total long-term disability trust	6		—		—		—		163		Total long-term disability trust	5		0		0		—		163
TOTAL ASSETS	TOTAL ASSETS	$	4,381	$	921	$	159	$	5	$	5,640	TOTAL ASSETS	$	3,676	$	1011	$	165	$	102	$	5,139
Liabilities:	Liabilities:											Liabilities:
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	0		5		259		(20)		244
Gas	Gas	—		—		—		—		—		Gas	0		5		0		(3)		2
TOTAL LIABILITIES	TOTAL LIABILITIES	$	—	$	5	$	164	$	(7)	$	162	TOTAL LIABILITIES	$	0	$	10	$	259	$	(23)	$	246


		Price Risk Management Instruments							Price Risk Management Instruments
(in millions)	(in millions)	2020		2019		(in millions)	2021		2020
Asset balance as of January 1	Asset balance as of January 1	$	5	$	95	Asset balance as of January 1	$	(72)	$	5
Net realized and unrealized gains:
Net realized and unrealized gains (losses):						Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts ⁽¹⁾	Included in regulatory assets and liabilities or balancing accounts ⁽¹⁾	(10)		34		Included in regulatory assets and liabilities or balancing accounts (1)	(22)		(10)
Asset balance as of March 31		$	(5)	$	129
Asset (liability) balance as of March 31						Asset (liability) balance as of March 31	$	(94)	$	(5)


		At March 31, 2020						At December 31, 2019							At March 31, 2021				At December 31, 2020
(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		Level 2 Fair Value
Debt (Note 5)	Debt (Note 5)									Debt (Note 5)
PG&E Corporation⁽¹⁾	PG&E Corporation⁽¹⁾	$	—	$	—	$	—	$	—	PG&E Corporation⁽¹⁾	$	3,372	$	2,118	$	1,901	$	2,175
Utility⁽²⁾	Utility⁽²⁾	2,000		2,007		1,500		1,500		Utility⁽²⁾	32,056		33,200		29,664		32,632


	As of
(in millions)	March 31, ~~2020~~2021
Less than 1 year	$	2632
1–5 years	~~397~~501
5–10 years	~~408~~427
More than 10 years	~~687~~805
Total maturities of fixed-income securities	$	~~1,518~~1,765


Insurance Receivable (in millions)	2020 Zogg fire		2019 Kincade fire		2017 Northern California wildfires		Total
Balance at December 31, 2020	$	219	$	430	$	25	$	674
Accrued insurance recoveries	28		0		0		28
Reimbursements	0		0		0		0
Balance at March 31, 2021	$	247	$	430	$	25	$	702


		Three Months Ended March 31, 2020										Three Months Ended March 31, 2019											Three Months Ended March 31, 2021				Three Months Ended March 31, 2020
		Revenues/Costs:										Revenues/Costs:											Revenues/Costs:				Revenues/Costs:
(in millions)	(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	Electric operating revenues	$	2,155	$	885	$	3,040	$	1,913	$	879	$	2,792	Electric operating revenues	$	2,343	$	1,052	$	3,395	$	2,155	$	885	$	3,040
Natural gas operating revenues	Natural gas operating revenues	864		402		1,266		794		425		1,219		Natural gas operating revenues	897		424		1,321		864		402		1,266
Total operating revenues	Total operating revenues	3,019		1,287		4,306		2,707		1,304		4,011		Total operating revenues	3,240		1,476		4,716		3,019		1,287		4,306
Cost of electricity	Cost of electricity	—		545		545		—		599		599		Cost of electricity	—		590		590		—		545		545
Cost of natural gas	Cost of natural gas	—		284		284		—		339		339		Cost of natural gas	—		307		307		—		284		284
Operating and maintenance	Operating and maintenance	1,463		502		1,965		1,694		410		2,104		Operating and maintenance	1,708		623		2,331		1,463		502		1,965
Wildfire-related claims, net of insurance recoveries														Wildfire-related claims, net of insurance recoveries	172		—		172		—		—		—
Wildfire Fund expense														Wildfire Fund expense	119		—		119		—		—		—
Depreciation, amortization, and decommissioning	Depreciation, amortization, and decommissioning	855		—		855		797		—		797		Depreciation, amortization, and decommissioning	888		—		888		855		—		855
Total operating expenses	Total operating expenses	2,318		1,331		3,649		2,491		1,348		3,839		Total operating expenses	2,887		1,520		4,407		2,318		1,331		3,649
Operating income (loss)	Operating income (loss)	701		(44)		657		216		(44)		172		Operating income (loss)	353		(44)		309		701		(44)		657
Interest income	Interest income	16		—		16		21		—		21		Interest income	2		—		2		16		—		16
Interest expense	Interest expense	(252)		—		(252)		(101)		—		(101)		Interest expense	(348)		—		(348)		(252)		—		(252)
Other income, net	Other income, net	49		44		93		22		44		66		Other income, net	89		44		133		49		44		93
Reorganization items		(93)		—		(93)		(111)		—		(111)
Reorganization items, net														Reorganization items, net	(2)		—		(2)		(93)		—		(93)
Income before income taxes	Income before income taxes	$	421	$	—	$	421	$	47	$	—	$	47	Income before income taxes	$	94	$	—	$	94	$	421	$	—	$	421
Income tax benefit ⁽¹⁾	Income tax benefit ⁽¹⁾					(30)						(86)		Income tax benefit (1)					(83)						(30)
Net income	Net income					451						133		Net income					177						451
Preferred stock dividend requirement⁽¹⁾	Preferred stock dividend requirement⁽¹⁾					3						—		Preferred stock dividend requirement (1)					3						3
Income Available for Common Stock						$	448					$	133
Income Attributable to Common Stock														Income Attributable to Common Stock					$	174					$	448


3.1						Amended and Restated Articles of Incorporation of PG&E Corporation, effective as of May 29, 2002, as amended by the Amendment dated June ~~21, 2019 [Conformed Copy]~~22, 2020 (incorporated by reference to PG&E Corporation’s Form ~~10-Q for the quarter ended~~8-K dated June ~~30, 2019~~20, 2020 (File No. 1-12609), Exhibit 3.1)

3.2						~~Certificate~~Bylaws of ~~Determination for~~ PG&E Corporation, ~~Series A Preferred Stock filed December~~Amended and Restated as of June 22, ~~2000~~2020 (incorporated by reference to PG&E Corporation’s Form ~~10-K for the year ended December 31, 2000~~8-K dated June 20, 2020 (File No. 1-12609), Exhibit ~~3.2)~~3.3)

3.3						~~Bylaws of PG&E Corporation amended as of April 10, 2019 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2019 (File No. 1-12609), Exhibit 3.1)~~

~~3.4~~						Amended and Restated Articles of Incorporation of Pacific Gas and Electric Company, effective as of ~~April 12, 2004~~June 22, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated ~~April 12, 2004~~June 20, 2020 (File No. 1-2348), Exhibit 3)3.2)


~~3.5~~3.4		Bylaws of Pacific Gas and Electric Company, ~~amended~~Amended and Restated as of ~~October~~June 22, 2020 (incorporated by reference in Form 8-K dated June 20, 2020 (File No. 1-2348), Exhibit 3.4)

4.1		Eighth Supplemental Indenture, dated March 11, ~~2019~~2021, relating to the Mortgage Bonds, between Pacific Gas and Electric Company and the Trustee (including the form of Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form ~~10-Q for the quarter ended September 30, 2019~~8-K dated March 8, 2021 (File No. 1-2348), Exhibit ~~3.1)~~4.1)

10.1		~~Restructuring Support~~Underwriting Agreement, dated ~~as of January 22, 2020,~~March 8, 2021, by and among ~~PG&E Corporation and~~ Pacific Gas and Electric Company, ~~Apollo~~BNP Paribas Securities Corp., Citigroup Global ~~Management LLC, Elliott Management Corporation, Oaktree Capital Management L.P., Farallon Capital Management LLC, Capital Group, Värde Partners~~Markets Inc., ~~Davidson Kempner Capital Management LP, Canyon Capital Advisors LLC, Third Point LLC, Pacific Investment Management Company LLC, Citadel Advisors~~Credit Suisse Securities (USA) LLC and Sculptor Capital Investments, LLC, certain funds and accounts managed or advised by Abrams Capital Management, LP and certain funds and accounts managed or advised by Knighthead Capital Management, LLCMUFG Securities Americas Inc. (incorporated by reference to ~~PG&E Corporation’s~~Pacific Gas and Electric Company’s Form 8-K ~~filed on January 23, 2020,~~dated March 8, 2021 (File No. ~~1-12609,~~1-2348), Exhibit ~~10.1)~~1.1)

10.2		~~Form of Joinder Agreement to~~Repricing Amendment, dated February 1, 2021, by and among PG&E Corporation, the ~~Restructuring Support Agreement dated~~Consenting Lenders, the New Lenders (each as ~~of January 22, 2020 (incorporated by reference to Exhibit 10.1 to the Debtors’ Current Report on Form 8-K, filed on January 23, 2020)~~defined therein) and JPMorgan Chase Bank, N.A, as administrative agent

10.3		Amendment No. 31 to Purchase and Sale Agreement, dated as of January 14, 2021, by and between PG&E ~~Corporation Commitment Letter~~AR Facility, LLC, as buyer, and Pacific Gas and Electric Company in its capacity as initial Servicer and in its capacity as Originator (incorporated by reference to PG&E Corporation’s Form ~~8-K filed on January 31, 2020~~10-K dated February 25, 2021 (File No. ~~1-12609,~~1-12609), Exhibit ~~10.2)~~10.75)

10.4		Amendment No. 31 to Receivables Financing Agreement, dated as of January 14, 2021, by and among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, ~~Commitment Letter~~in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (incorporated by reference to ~~Pacific Gas and Electric Company~~PG&E Corporation’s Form ~~8-K filed on January 31, 2020~~10-K dated February 25, 2021 (File No. ~~1-02348,~~1-12609), Exhibit ~~10.3)~~10.77)

10.5	*	~~Form~~Amendment No. 2 to Receivables Financing Agreement, dated as of ~~Amended~~February 12, 2021, by and ~~Restated Chapter 11 Plan Backstop Commitment Letter~~among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (incorporated by reference to PG&E Corporation’s Form ~~8-K~~10-K dated ~~March 6, 2020~~February 25, 2021 (File No. 1-12609), Exhibit ~~10.1)~~10.78)

10.6		~~Plea~~Master Transaction Agreement, dated as of February 2, 2021, by and ~~Settlement dated March 17, 2020~~between Pacific Gas and Electric Company and Golden State Licensing, LLC (incorporated by reference to PG&E Corporation’s Form ~~8-K filed on March 23,2020~~10-K dated February 25, 2021 (File No. 1-12609), Exhibit ~~10.1)~~10.80)

10.7	*	~~Settlement Agreement~~Offer Letter between Pacific Gas and Electric Company and Adam L. Wright, dated April 21, 2020 by and among the TCC, PG&E Corporation and the Utility, FEMA, the SBA, the Department of Agriculture, the Department of the Interior, the United States Department of Housing and Urban Development and the General Services AdministrationJanuary 16, 2021

10.8	*	~~Settlement~~Restricted Stock Unit Agreement between Adam L. Wright and Pacific Gas and Electric Company, dated ~~April 21, 2020 by~~March 1, 2021

10.9	*	Offer Letter between Pacific Gas and ~~among the TCC,~~Electric Company and Marlene M. Santos, dated January 26, 2021

10.10	*	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Marlene M. Santos, dated March 15, 2021

10.11	*	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Christopher A. Foster, dated March 22, 2021

10.12		Offer Letter between Pacific Gas and Electric Company and Jason M. Glickman, dated March 24, 2021

10.13	*	Form of Restricted Stock Unit Agreement for 2021 grants under the ~~Utility, Cal DDS, Cal DTSC, Cal Fire, Cal OES, Cal Parks, CSU, Caltrans~~PG&E Corporation 2014 Long-Term Incentive Plan

10.14	*	Form of Performance Share Unit Agreement subject to customer experience, public safety and ~~Cal Vet~~financial goals for 2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan

10.15	*	Form of Performance Share Unit Agreement subject to total shareholder return goals for 2021 grants under the PG&E Corporation 2014 Long-Term Incentive Plan

10.16	*	Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2021 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 9, 2021 (File No. 1-12609))

31.1	**	Certifications of Principal Executive Officer and Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	**	Certifications of Principal Executive ~~Officers~~Officer s and Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002


32.1	***	Certifications of Principal Executive Officer and Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2	***	Certifications of Principal Executive Officers and Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002


PG&E CORPORATION

/s/ ~~JASON P. WELLS~~CHRISTOPHER A. FOSTER
~~Jason P. Wells~~Christopher A. Foster Executive Vice President and Chief Financial Officer (duly authorized officer and principal financial officer)


PACIFIC GAS AND ELECTRIC COMPANY

/s/ DAVID S. THOMASON
David S. Thomason Vice President, Chief Financial Officer and Controller (duly authorized officer and principal financial officer)